form10-q.htm

10-Q 1 form10-q.htm FORM 10-Q form10-q.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED March 31, 2009

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO

	Registrant, Address of	I.R.S. Employer
	Principal Executive Offices	Identification	State of
Commission File Number	and Telephone Number	Number	Incorporation

1-08788	NV ENERGY, INC.	88-0198358	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000

2-28348	NEVADA POWER COMPANY d/b/a	88-0420104	Nevada
	NV ENERGY
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000

0-00508	SIERRA PACIFIC POWER COMPANY d/b/a	88-0044418	Nevada
	NV ENERGY
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (89511)
	(775) 834-4011

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o (Response applicable to all registrants)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes______ No (Response applicable to all registrants)

Indicate by check mark whether any registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer", "accelerated filer”, "non-accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

NV Energy, Inc.:	Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
Nevada Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o
Sierra Pacific Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ (Response applicable to all registrants)

Indicate the number of shares outstanding of each of the issuer’s classes of Common Stock, as of the latest practicable date.

Class		Outstanding at April 30, 2009
Common Stock, $1.00 par value of NV Energy, Inc.		234,395,695 Shares

NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding Common Stock, $1.00 stated value, of Nevada Power Company.

NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding Common Stock, $3.75 stated value, of Sierra Pacific Power Company.

This combined Quarterly Report on Form 10-Q is separately filed by NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company. Information contained in this document relating to Nevada Power Company is filed by NV Energy, Inc. and separately by Nevada Power Company on its own behalf. Nevada Power Company makes no representation as to information relating to NV Energy, Inc. or its subsidiaries, except as it may relate to Nevada Power Company. Information contained in this document relating to Sierra Pacific Power Company is filed by NV Energy, Inc. and separately by Sierra Pacific Power Company on its own behalf. Sierra Pacific Power Company makes no representation as to information relating to NV Energy, Inc. or its subsidiaries, except as it may relate to Sierra Pacific Power Company.

NV ENERGY, INC.

NEVADA POWER COMPANY

SIERRA PACIFIC POWER COMPANY

QUARTERLY REPORTS ON FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2009

TABLE OF CONTENTS

Acronyms and Terms...................................................................................................................................................................................		3

PART I - FINANCIAL INFORMATION

ITEM 1.	Financial Statements

NV Energy, Inc.

	Consolidated Balance Sheets – March 31, 2009 and December 31, 2008…………...……...……………...................................................................	4
	Consolidated Statements of Operations – Three Months Ended March 31, 2009 and 2008…………………………………………………........	5
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2009 and 2008………………….......................................................	6

Nevada Power Company -

	Consolidated Balance Sheets – March 31, 2009 and December 31, 2008…………...……...……………...................................................................	7
	Consolidated Statements of Operations – Three Months Ended March 31, 2009 and 2008………………………………………………….........	8
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2009 and 2008…………………........................................................	9

Sierra Pacific Power Company -

	Consolidated Balance Sheets – March 31, 2009 and December 31, 2008…………...……...…………......................................................................	10
	Consolidated Statements of Income – Three Months Ended March 31, 2009 and 2008……………………………………………………...........	11
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2009 and 2008………………………………………………...........	12

	Condensed Notes to Consolidated Financial Statements………………………………………………………………………………….................	13

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations………………………………………………........	26

	NV Energy, Inc.……………..…………………………………………….…………………………….............................................................................	30
	Nevada Power Company …………………………………………………….………………………………………………………...............................	36
	Sierra Pacific Power Company ………………………………………………………………………………………………………...............................	43

ITEM 3A.	Quantitative and Qualitative Disclosures about Market Risk………………………………………………………………………………...............	52

ITEM 4 and 4T.	Controls and Procedures……………………………………………………………………………………………………………………....................	52

PART II - OTHER INFORMATION

ITEM 1.	Legal Proceedings…………………………………………………………………………...……………..........................................................................	53

ITEM 1A.	Risk Factors…………………………………………………………………………………………………………………………..................................	53

ITEM 2.	Unregistered Sales of Equity Securities and use of Proceeds......................................................................................................................................	53

ITEM 3.	Defaults Upon Senior Securities........................................................................................................................................................................................	53

ITEM 4.	Submission of Matters to a Vote of Security Holders....................................................................................................................................................	53

ITEM 5.	Other Information.................................................................................................................................................................................................................	54

ITEM 6.	Exhibits..................................................................................................................................................................................................................................	55

Signature Page and Certifications..................................................................................................................................................................................................................		56

ACRONYMS AND TERMS
(The following common acronyms and terms are found in multiple locations within the document)

Acronyms/Terms		Meaning

2008 Form 10-K		NVE’s NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2008
AFUDC		Allowance for Funds Used During Construction or Allowance for Borrowed Funds Used During Construction
APB 28-1		Accounting Principles Board 28-1, “Interim Financial Reporting”
BTER		Base Tariff Energy Rate
BTGR		Base Tariff General Rate
Clark Generating Station		550 megawatt nominally rated William Clark Generating Station
Clark Peaking Units		600 megawatt nominally rated peaking units at the William Clark Generating Station
CPUC		California Public Utilities Commission
CWIP		Construction Work-In-Progress
DBRS		Dominion Bond Rating Service
DEAA		Deferred Energy Accounting Adjustment
DOS		Distribution Only Service
DSM		Demand Side Management
Dth		Decatherm
EEC		Ely Energy Center
EPS		Earnings Per Share
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Ratings, Ltd.
FSP 107-1		FASB Staff Position No. 107-1, “Interim Disclosure about Fair Value of Financial Instruments”
FSP 157-2		FASB Staff Position No. 157-2, “Defers the effective date for certain portions of SFAS 157 related to nonrecurring measurement of nonfinancial assets and liabilities”
FSP 157-4		FASB Staff Position No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions that are not Orderly”
GAAP		Accounting Principles Generally Accepted in the United States
GRC		General Rate Case
Higgins Generating Station		598 megawatt nominally rated Walter M. Higgins, III Generating Station
IRP		Integrated Resource Plan
Moody’s		Moody’s Investors Services, Inc.
MW		Megawatt
MWh		Megawatt hour
NEICO		Nevada Electrical Investment Company
NPC		Nevada Power Company d/b/a NV Energy
NVE		NV Energy, Inc.
ON Line		250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
PEC		Portfolio Energy Credit
Portfolio Standard		Renewable Energy Portfolio Standard
PUCN		Public Utilities Commission of Nevada
ROE		Return on Equity
ROR		Rate of Return
S&P		Standard and Poor’s
Salt River		Salt River Project
SEC		Securities and Exchange Commission
SFAS 71		Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 128		Statement of Financial Accounting Standards No. 128, "Earnings Per Share"
SFAS 131		Statement of Financial Accounting Standards No. 131, "Disclosure About Segments of an Enterprise and Related Information"
SFAS 133		Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 138		Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133"
SFAS 144		Statement of Financial Accounting Standards No. 144, “Accounting for the Disposal or Impairment of Long-Lived Assets”
SFAS 149		Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities"
SFAS 155		Statement of Financial Accounting Standards No. 155, "Accounting for Certain Hybrid Financial Instruments - An Amendment of FASB Statements No. 133 and 140"
SFAS 157		Statement of Financial Accounting Standards No. 157, “Fair Value Measurement”
SFAS 158		Statement of Financial Accounting Standards No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans”
SFAS 161		Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activity”
SPPC		Sierra Pacific Power Company d/b/a NV Energy
TMWA		Truckee Meadows Water Authority
Tracy Generating Station		541 megawatt nominally rated Frank A. Tracy Generating Station
U.S.		United States of America
WSPP		Western Systems Power Pool

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		March 31,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	10,455,344	$	10,358,843
Less accumulated provision for depreciation			2,714,889		2,659,219
			7,740,455		7,699,624
Construction work-in-progress			687,839		610,667
			8,428,294		8,310,291

Investments and other property, net			25,061		25,189

Current Assets:
Cash and cash equivalents			113,281		54,359
Accounts receivable less allowance for uncollectible accounts:
	2009 - $30,842, 2008 - $32,695		374,470		415,856
Deferred energy costs - electric (Note 3)			91,286		50,436
Materials, supplies and fuel, at average cost			124,311		125,391
Risk management assets (Note 5)			13,602		16,118
Current income taxes receivable			5,487		5,487
Deferred income taxes			76,817		49,996
Other			55,532		52,633
			854,786		770,276
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 3)			154,248		231,027
Regulatory assets			1,504,203		1,415,436
Regulatory asset for pension plans			406,039		413,544
Risk management assets (Note 5)			6,694		9,959
Other			174,478		170,258
			2,245,662		2,240,224
TOTAL ASSETS		$	11,553,803	$	11,345,980

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity		$	3,086,337	$	3,131,186
Long-term debt			5,485,643		5,266,982
			8,571,980		8,398,168
Current Liabilities:
Current maturities of long-term debt			8,885		9,291
Accounts payable			360,922		400,084
Accrued expenses			112,294		131,720
Risk management liabilities (Note 5)			412,519		313,846
Other			119,342		114,442
			1,013,962		969,383
Commitments and Contingencies (Note 6)

Deferred Credits and Other Liabilities:
Deferred income taxes			936,550		920,481
Deferred investment tax credit			25,187		25,923
Accrued retirement benefits			276,636		288,841
Risk management liabilities (Note 5)			30,942		53,403
Regulatory liabilities			367,490		361,337
Other			331,056		328,444
			1,967,861		1,978,429
TOTAL CAPITALIZATION AND LIABILITIES		$	11,553,803	$	11,345,980

The accompanying notes are an integral part of the financial statements.

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands, Except Per Share Amount)
(Unaudited)

	Three Months Ended
	March 31,
	2009			2008

OPERATING REVENUES:
Electric	$	674,267		$	719,450
Gas		80,993			85,594
Other		7			7
		755,267			805,051
OPERATING EXPENSES:
Operation:
Fuel for power generation		230,104			221,608
Purchased power		125,387			183,856
Gas purchased for resale		70,272			66,896
Deferral of energy costs - electric - net		49,986			54,282
Deferral of energy costs - gas – net		(4,351	)		2,203
Other		114,677			91,675
Maintenance		34,400			23,122
Depreciation and amortization		78,048			62,070
Taxes:
Income taxes (benefit)		(13,656	)		8,619
Other than income		14,647			13,907
		699,514			728,238
OPERATING INCOME		55,753			76,813

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		6,218			11,957
Interest accrued on deferred energy		1,180			1,236
Other income		5,058			13,672
Other expense		(5,578	)		(3,027	)
Income taxes		(2,242	)		(8,089	)
		4,636			15,749
Total Income Before Interest Charges		60,389			92,562

INTEREST CHARGES:
Long-term debt		78,557			69,955
Other		9,222			7,701
Allowance for borrowed funds used during construction		(5,146	)		(9,152	)
		82,633			68,504

NET INCOME (LOSS)	$	(22,244	)	$	24,058

Amount per share basic and diluted - (Note 7)
Net Income (Loss) per share – basic and diluted	$	(0.09	)	$	0.10

Weighted Average Shares of Common Stock Outstanding - basic		234,331,044			233,836,234
Weighted Average Shares of Common Stock Outstanding - diluted		234,331,044			234,321,972
Dividends Declared Per Share of Common Stock	$	0.10		$	0.08

The accompanying notes are an integral part of the financial statements.

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	(22,244	)	$	24,058
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		78,048			62,070
Deferred taxes and deferred investment tax credit		5,264			9,482
AFUDC		(6,218	)		(11,957	)
Amortization of energy costs, net of deferrals		45,803			58,847
Other, net		16,836			(9,394	)
Changes in certain assets and liabilities:
Accounts receivable		23,909			59,799
Materials, supplies and fuel		1,080			7,289
Other current assets		(2,899	)		1,617
Accounts payable		(41,216	)		(16,128	)
Accrued retirement benefits		(12,205	)		4,537
Other current liabilities		(24,400	)		5,331
Risk management assets and liabilities		267			(352	)
Other deferred assets		(3,988	)		(5,925	)
Other regulatory assets		(11,251	)		(16,508	)
Other deferred liabilities		4,493			(10,859	)
Net Cash from Operating Activities		51,279			161,907

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(197,498	)		(225,465	)
Customer advances for construction		(3,260	)		(783	)
Contributions in aid of construction		17,104			32,475
Investments and other property – net		9			4,392
Net Cash used by Investing Activities		(183,645	)		(189,381	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		909,020			40,000
Retirement of long-term debt		(695,100	)		(4,364	)
Sale of Common Stock		818			2,253
Dividends paid		(23,450	)		(18,798	)
Net Cash from Financing Activities		191,288			19,091

Net Increase (Decrease) in Cash and Cash Equivalents		58,922			(8,383	)
Beginning Balance in Cash and Cash Equivalents		54,359			129,140
Ending Balance in Cash and Cash Equivalents	$	113,281		$	120,757

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	92,750		$	68,326
Income taxes	$	-		$	3,544

The accompanying notes are an integral part of the financial statements

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		March 31,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	6,954,369	$	6,884,033
Less accumulated provision for depreciation			1,538,558		1,500,502
			5,415,811		5,383,531
Construction work-in-progress			577,395		514,096
			5,993,206		5,897,627

Investments and other property, net			19,587		19,701

Current Assets:
Cash and cash equivalents			81,571		28,594
Accounts receivable less allowance for uncollectible accounts:
	2009 - $28,516 , 2008 - $30,621		225,572		238,379
Deferred energy costs - electric (Note 3)			91,286		50,436
Materials, supplies and fuel, at average cost			75,085		74,103
Risk management assets (Note 5)			10,278		11,724
Intercompany income taxes receivable			56,593		20,695
Deferred income taxes			-		2,682
Other			39,605		34,657
			579,990		461,270
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 3)			154,248		231,027
Regulatory assets			1,051,137		971,354
Regulatory asset for pension plans			184,472		187,894
Risk management assets (Note 5)			5,336		7,346
Other			132,476		127,928
			1,527,669		1,525,549
TOTAL ASSETS		$	8,120,452	$	7,904,147

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity		$	2,570,426	$	2,627,567
Long-term debt			3,596,840		3,385,106
			6,167,266		6,012,673
Current Liabilities:
Current maturities of long-term debt			8,885		8,691
Accounts payable			266,499		262,552
Accounts payable, affiliated companies			23,557		32,901
Accrued expenses			75,278		80,069
Deferred income taxes			12,772		-
Risk management liabilities (Note 5)			300,800		222,856
Other			68,498		72,762
			756,289		679,831
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes			641,860		635,523
Deferred investment tax credit			9,711		10,001
Accrued retirement benefits			86,443		103,023
Risk management liabilities (Note 5)			23,281		35,241
Regulatory liabilities			193,336		188,709
Other			242,266		239,146
			1,196,897		1,211,643

TOTAL CAPITALIZATION AND LIABILITIES		$	8,120,452	$	7,904,147

The accompanying notes are an integral part of the financial statements.

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands)
(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
OPERATING REVENUES:
Electric	$	436,529		$	469,172

OPERATING EXPENSES:
Operation:
Fuel for power generation		154,062			164,021
Purchased power		88,206			93,750
Deferral of energy costs-net		38,190			45,775
Other		70,193			57,095
Maintenance		27,534			16,650
Depreciation and amortization		52,363			40,630
Taxes:
Income taxes (benefit)		(18,547	)		2,132
Other than income		9,063			8,322
		421,064			428,375
OPERATING INCOME		15,465			40,797

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		5,621			6,858
Interest accrued on deferred energy		1,853			1,794
Other income		2,342			5,747
Other expense		(3,207	)		(1,361	)
Income taxes		(2,182	)		(4,391	)
		4,427			8,647
Total Income Before Interest Charges		19,892			49,444

INTEREST CHARGES:
Long-term debt		52,308			40,997
Other		7,297			5,831
Allowance for borrowed funds used during construction		(4,562	)		(5,355	)
		55,043			41,473

NET INCOME (LOSS)	$	(35,151	)	$	7,971

The accompanying notes are an integral part of the financial statements.

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
Net Income (Loss)	$	(35,151	)	$	7,971
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		52,363			40,630
Deferred taxes and deferred investment tax credit		19,424			(14,443	)
AFUDC		(5,621	)		(6,858	)
Amortization of energy costs, net of deferrals		35,928			44,042
Other, net		10,269			(6,784	)
Changes in certain assets and liabilities:
Accounts receivable		(23,090	)		35,952
Materials, supplies and fuel		(982	)		4,623
Other current assets		(4,948	)		(590	)
Accounts payable		(17,299	)		(18,882	)
Accrued retirement benefits		(16,580	)		4,396
Other current liabilities		(9,056	)		13,716
Risk management assets and liabilities		(532	)		(553	)
Other deferred assets		(3,445	)		(8,834	)
Other regulatory assets		(10,572	)		(9,099	)
Other deferred liabilities		4,118			(8,426	)
Net Cash From (Used By) Operating Activities		(5,174	)		76,861

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(141,059	)		(156,302	)
Customer advances for construction		(2,101	)		(1,879	)
Contributions in aid of construction		15,603			28,057
Investments and other property – net		(4	)		2,821
Net Cash used by Investing Activities		(127,561	)		(127,303	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		748,404			40,000
Retirement of long-term debt		(540,692	)		(3,539	)
Additional investment by parent company		-			53,000
Dividends paid		(22,000	)		(24,907	)
Net Cash from Financing Activities		185,712			64,554

Net Increase (Decrease) in Cash and Cash Equivalents		52,977			14,112
Beginning Balance in Cash and Cash Equivalents		28,594			37,001
Ending Balance in Cash and Cash Equivalents	$	81,571		$	51,113

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	55,611		$	34,751
Income taxes	$	-		$	3,544

The accompanying notes are an integral part of the financial statements.

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
		March 31,		December 31,
		2009		2008
ASSETS
Utility Plant at Original Cost:
Plant in service		$	3,500,975	$	3,474,810
Less accumulated provision for depreciation			1,176,331		1,158,717
			2,324,644		2,316,093
Construction work-in-progress			110,444		96,571
			2,435,088		2,412,664

Investments and other property, net			397		411

Current Assets:
Cash and cash equivalents			28,930		21,411
Accounts receivable less allowance for uncollectible accounts:
	2009 - $2,326; 2008 - $2,073		148,841		177,401
Materials, supplies and fuel, at average cost			49,167		51,252
Risk management assets (Note 5)			3,324		4,394
Intercompany income taxes receivable			64,591		64,932
Deferred income taxes			14,577		12,253
Other			15,803		17,631
			325,233		349,274
Deferred Charges and Other Assets:
Regulatory assets			453,066		444,082
Regulatory asset for pension plans			214,651		218,550
Risk management assets (Note 5)			1,358		2,613
Other			34,602		34,951
			703,677		700,196
TOTAL ASSETS		$	3,464,395	$	3,462,545

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity		$	975,406	$	877,961
Long-term debt			1,402,964		1,395,987
			2,378,370		2,273,948
Current Liabilities:
Current maturities of long-term debt			-		600
Accounts payable			79,446		109,410
Accounts payable, affiliated companies			14,480		17,433
Accrued expenses			31,825		37,787
Dividends declared			-		96,800
Risk management liabilities (Note 5)			111,719		90,990
Other			50,844		41,680
			288,314		394,700
Commitments and Contingencies (Note 6)
Deferred Credits and Other Liabilities:
Deferred income taxes			297,267		287,251
Deferred investment tax credit			15,476		15,922
Accrued retirement benefits			184,389		180,209
Risk management liabilities (Note 5)			7,661		18,162
Regulatory liabilities			174,154		172,628
Other			118,764		119,725
			797,711		793,897
TOTAL CAPITALIZATION AND LIABILITIES		$	3,464,395	$	3,462,545

The accompanying notes are an integral part of the financial statements.

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
OPERATING REVENUES:
Electric	$	237,738		$	250,278
Gas		80,993			85,594
		318,731			335,872
OPERATING EXPENSES:
Operation:
Fuel for power generation		76,042			57,587
Purchased power		37,181			90,106
Gas purchased for resale		70,272			66,896
Deferral of energy costs - electric – net		11,796			8,507
Deferral of energy costs - gas – net		(4,351	)		2,203
Other		44,015			33,505
Maintenance		6,866			6,472
Depreciation and amortization		25,685			21,440
Taxes:
Income taxes		9,078			9,659
Other than income		5,524			5,528
		282,108			301,903
OPERATING INCOME		36,623			33,969

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		597			5,099
Interest accrued on deferred energy		(673	)		(558	)
Other income		2,715			7,735
Other expense		(1,991	)		(1,800	)
Income taxes		(208	)		(3,574	)
		440			6,902
Total Income Before Interest Charges		37,063			40,871

INTEREST CHARGES:
Long-term debt		16,815			18,762
Other		1,696			1,622
Allowance for borrowed funds used during construction		(584	)		(3,797	)
		17,927			16,587

NET INCOME	$	19,136		$	24,284

The accompanying notes are an integral part of the financial statements.

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	19,136		$	24,284
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		25,685			21,440
Deferred taxes and deferred investment tax credit		8,597			9,629
AFUDC		(597	)		(5,099	)
Amortization of energy costs, net of deferrals		9,875			14,805
Other, net		6,395			(1,310	)
Changes in certain assets and liabilities:
Accounts receivable		28,901			23,930
Materials, supplies and fuel		2,085			2,669
Other current assets		1,828			2,050
Accounts payable		(23,069	)		(500	)
Accrued retirement benefits		4,179			(643	)
Other current liabilities		(6,672	)		806
Risk management assets and liabilities		799			201
Other deferred assets		(543	)		2,909
Other regulatory assets		(679	)		(7,409	)
Other deferred liabilities		(75	)		(294	)
Net Cash from Operating Activities		75,845			87,468

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(56,439	)		(69,163	)
Customer advances for construction		(1,159	)		1,096
Contributions in aid of construction		1,501			4,418
Investments and other property - net		14			1,570
Net Cash used by Investing Activities		(56,083	)		(62,079	)

CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		160,616			-
Retirement of long-term debt		(154,359	)		(771	)
Investment by parent company		90,300			20,000
Dividends paid		(108,800	)		(13,333	)
Net Cash From (Used By) Financing Activities		(12,243	)		5,896

Net Increase (Decrease) in Cash and Cash Equivalents		7,519			31,285
Beginning Balance in Cash and Cash Equivalents		21,411			23,807
Ending Balance in Cash and Cash Equivalents	$	28,930		$	55,092

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	20,755		$	15,688
Income taxes	$	-		$	-

The accompanying notes are an integral part of the financial statements.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies for both utility and non-utility operations are as follows:

Basis of Presentation

The consolidated financial statements include the accounts of NV Energy, Inc. and its wholly-owned subsidiaries, Nevada Power Company, Sierra Pacific Power Company, Tuscarora Gas Pipeline Company, which was dissolved in 2008, Sierra Pacific Communications, Lands of Sierra, Inc., Sierra Pacific Energy Company, Sierra Water Development Company and Sierra Gas Holding Company. All intercompany balances and intercompany transactions have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates.

In the opinion of the management of NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain normal and recurring adjustments necessary to present fairly the consolidated financial position, results of operations and cash flows for the periods shown. These consolidated financial statements do not contain the complete detail concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statements included in the 2008 Form 10-K.

The results of operations and cash flows of NVE, NPC and SPPC for the three months ended March 31, 2009, are not necessarily indicative of the results to be expected for the full year.

Reclassifications

Certain financial statement line items for prior periods have been re-grouped or reclassified to conform with current year presentation. The re-groupings or reclassifications have not affected previously reported results of operations or common shareholders’ equity.

Recent Pronouncements

SFAS 157-2

In February 2008, the FASB issued FSP 157-2, which deferred the effective date for certain portions of SFAS 157 related to nonrecurring measurements of nonfinancial assets and liabilities. SFAS 157-2 was effective for NVE and the Utilities beginning January 1, 2009. The adoption of SFAS 157-2 did not have a material impact on the consolidated financial statements.

SFAS 161

In March 2008, the FASB issued SFAS 161, and amendment of SFAS 133 which is effective for financial statements issued for fiscal years and interim period beginning after November 15, 2008. The purpose of SFAS 161 is to provide more adequate disclosure about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. NVE and the Utilities adopted SFAS 161 beginning January 1, 2009. See Note 5, Derivatives and Hedging Activities.

FSP FAS 107-1 and APB 28-1

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, requiring disclosure of fair values of certain financial instruments in interim financial statements. The provisions of FSP 107-1 and APB 28-1 are effective for NVE and the Utilities as of June 30, 2009. NVE and the Utilities will be required to report on an interim basis substantially similar disclosure as reported in Note 7, Fair Value of Financial Instruments of the Notes to Financial Statements in the 2008 Form 10-K.

SFAS 157-4

In April 2009, the FASB issued FSP 157-4, which provides additional guidance on measuring the fair value of financial instruments when markets become inactive and quoted prices may reflect distressed transactions. The provisions of FSP 157-4 are effective for NVE and the Utilities as of June 30, 2009. NVE and the Utilities are currently evaluating the impact of the adoption of FSP 157-4, but do not expect the adoption to have a material impact on their financial statements.

NOTE 2. SEGMENT INFORMATION

The Utilities operate three regulated business segments (as defined by SFAS 131) which are NPC electric, SPPC electric and SPPC natural gas service. Electric service is provided to Las Vegas and surrounding Clark County by NPC, and northern Nevada and the Lake Tahoe area of California by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative thresholds for separate disclosure.

Operational information of the different business segments is set forth below based on the nature of products and services offered. NVE evaluates performance based on several factors, of which the primary financial measure is business segment gross margin. Gross margin, which the Utilities calculate as operating revenues less fuel, purchased power, and deferred energy costs, provides a measure of income available to support the other operating expenses of the Utilities. Operating expenses are provided by segment in order to reconcile to operating income as reported in the consolidated financial statements (dollars in thousands).


Three months ended	NPC			SPPC		SPPC			SPPC		NVE			NVE
March 31, 2009	Electric			Electric		Gas			Total		Other			Consolidated
Operating Revenues	$	436,529		$	237,738	$	80,993		$	318,731	$	7		$	755,267

Energy Costs:
Fuel for power generation		154,062			76,042		-			76,042		-			230,104
Purchased power		88,206			37,181		-			37,181		-			125,387
Gas purchased for resale		-			-		70,272			70,272		-			70,272
Deferred energy costs - net		38,190			11,796		(4,351	)		7,445		-			45,635
	$	280,458		$	125,019	$	65,921		$	190,940	$	-		$	471,398

Gross Margin	$	156,071		$	112,719	$	15,072		$	127,791	$	7		$	283,869

Other		70,193								44,015		469			114,677
Maintenance		27,534								6,866		-			34,400
Depreciation and amortization		52,363								25,685		-			78,048
Taxes:
Income taxes (benefit)		(18,547	)							9,078		(4,187	)		(13,656	)
Other than income		9,063								5,524		60			14,647

Operating Income	$	15,465							$	36,623	$	3,665		$	55,753


Three months ended	NPC		SPPC		SPPC		SPPC		NVE			NVE
March 31, 2008	Electric		Electric		Gas		Total		Other			Consolidated
Operating Revenues	$	469,172	$	250,278	$	85,594	$	335,872	$	7		$	805,051

Energy Costs:
Fuel for power generation		164,021		57,587		-		57,587		-			221,608
Purchased power		93,750		90,106		-		90,106		-			183,856
Gas purchased for resale		-		-		66,896		66,896		-			66,896
Deferred energy costs - net		45,775		8,507		2,203		10,710		-			56,485
	$	303,546	$	156,200	$	69,099	$	225,299	$	-		$	528,845

Gross Margin	$	165,626	$	94,078	$	16,495	$	110,573	$	7		$	276,206

Other		57,095						33,505		1,075			91,675
Maintenance		16,650						6,472		-			23,122
Depreciation and amortization		40,630						21,440		-			62,070
Taxes:
Income taxes (benefit)		2,132						9,659		(3,172	)		8,619
Other than income		8,322						5,528		57			13,907

Operating Income	$	40,797					$	33,969	$	2,047		$	76,813

NOTE 3. REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting. See Note 3, Regulatory Actions of Notes to Financial Statements in NPC’s and SPPC’s 2008 Form 10-K, for additional information regarding deferred energy accounting by the Utilities.

The following deferred energy costs were included in the consolidated balance sheets as of the dates shown (dollars in thousands):

	March 31, 2009
Description	NPC Electric			SPPC Electric			SPPC Gas			NVE Total

Nevada Deferred Energy
Cumulative Balance requested in 2009 DEAA	$	77,473	(1)	$	(19,813	)	$	(8,733	)	$	48,927
2009 Amortization		8			282			-			290
2009 Deferred Energy Costs (2)		(29,290	)		(14,922	)		4,220			(39,992	)
Nevada Deferred Energy Balance at March 31, 2009 - Subtotal	$	48,191		$	(34,453	)	$	(4,513	)	$	9,225
Cumulative CPUC balance		-			2,435			-			2,435
Western Energy Crisis Rate Case (effective 6/07, 3 years)		36,972			-			-			36,972
Reinstatement of deferred energy (effective 6/07, 10 years)		160,371			-			-			160,371

Total	$	245,534		$	(32,018	)	$	(4,513	)	$	209,003

Current Assets
Deferred energy costs – electric		91,286			-			-			91,286
Deferred Assets
Deferred energy costs - electric		154,248			-			-			154,248
Other Current Liabilities		-			(32,018	)		(4,513	)		(36,531	)
Total	$	245,534		$	(32,018	)	$	(4,513	)	$	209,003

(1)	Reflects ordered adjustments.
(2)	These costs to be requested in 2010 DEAA filings in February 2010.

Pending Regulatory Actions

Nevada Power Company and Sierra Pacific Power Company

Ely Energy Center

On February 9, 2009, NVE and the Utilities announced their intention to postpone plans to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade. NVE and the Utilities still plan to proceed with the construction of the ON Line, which will link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state, allowing for the transfer of energy, including energy from renewable resources, between the Utilities. The PUCN had previously approved the Utilities spending on the EEC up to $130 million, of which the Utilities have spent and recorded as an other deferred asset approximately $72.6 million, including amounts related to the ON Line as of March 31, 2009. As such, management expects full recovery of the amounts expended through March 31, 2009.

Nevada Power Company

NPC 2009 Deferred Energy Rate Case

In February 2009, NPC filed an application to create a new DEAA rate. In this application, NPC requests to increase rates by $72.1 million, an increase of 3.18%, while recovering $77.5 million of deferred fuel and purchased power costs. The new DEAA rate, if approved, will be effective October 1, 2009.

NPC General Rate Case

In December 2008, NPC filed its statutorily required GRC. In this GRC, NPC is requesting the following:

·		Increase in general rates by $323.9 million, approximately a 14.95% increase;
·		ROE and ROR of 11.0% and 8.88%, respectively;
·		Authorization to recover the costs of major plant additions including the purchase of the Higgins Generating Station, construction of Clark Peaking Units, an upgrade to the emission control systems on existing units at the Clark Generating Station, installation of environmental equipment upgrades at the Reid Gardner Generating Station and new transmission and distribution projects;
·		CWIP in rate base for the construction of a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen site;
·		Implementation of a low-income rate discount for customers;
·		Delay the rate effective date from July 1, 2009 to September 1, 2009. The delay in the rate effective date is contingent on PUCN approval to track and defer the revenues that NPC would otherwise collect during this sixty day period in a regulatory asset account and permit that NPC be allowed to record a carrying charge on these amounts. NPC would seek authority to amortize this regulatory asset in its next GRC filing, currently scheduled for December 2011.

In February 2009, NPC submitted its certification filing which lowered the increase in general rates to $310.9 million, an approximate 13.64% increase, and lowered the requested ROR to 8.75%. Hearings are scheduled in mid-April through early May and, if approved, the new rates would be effective July 1, 2009; however, the collection period would not begin until September 1, 2009.

Sierra Pacific Power Company

SPPC Nevada Gas DEAA

In February 2009, SPPC filed an application to create a new DEAA rate. In this application, SPPC requests to decrease rates by $8.7 million, a decrease of 4.71%, while refunding $8.7 million of deferred gas costs. The new DEAA rate, if approved, will be effective October 1, 2009.

SPPC Nevada Electric DEAA

In February 2009, SPPC filed an application to create a new DEAA rate. In this application, SPPC requests to decrease rates by $25.9 million, a decrease of 2.69%, while refunding $19.8 million of deferred fuel and purchased power costs. The new DEAA rate will be effective October 1, 2009.

SPPC California General Rate Case

In July 2008, SPPC filed a GRC and subsequently an amendment in December 2008 to the original filing. SPPC requested the following:

·		Increase in general rates of $8.9 million, approximately an 11% increase;
·		ROE and ROR of 11.4% and 8.81%, respectively;
·		Authorization to recover the costs of major plant additions, which include the Tracy Generating Station, distribution plant additions and an increase to the California Energy Efficiency Program;
·		A two-part mechanism to recover changes in non-energy cost adjustment clause costs incurred during the two years between rate cases.

Hearings are scheduled for June 2009 and, if approved, the new rates would be effective at the earliest on December 1, 2009.

NOTE 4. LONG-TERM DEBT

As of March 31, 2009, NPC’s, SPPC’s and NVE’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years and thereafter are shown below (dollars in thousands):

	NPC			SPPC		NVE Holding Co. and Other Subs.		NVE Consolidated
2009	$	3,536		$	-	$	-	$	3,536
2010		8,004			199,930		-		207,934
2011		369,924			-		-		369,924
2012		136,449			100,000		63,670		300,119
2013		7,146			250,000		-		257,146
		525,059			549,930		63,670		1,138,659
Thereafter		3,093,360			843,500		421,539		4,358,399
		3,618,419			1,393,430		485,209		5,497,058
Unamortized Premium(Discount) Amount		(12,694	)		9,534		630		(2,530	)
Total	$	3,605,725		$	1,402,964	$	485,839	$	5,494,528

Substantially all utility plant is subject to the liens of NPC’s and SPPC’s indentures under which their respective General and Refunding Mortgage bonds are issued.

Nevada Power Company

Revolving Credit Facilities

On March 2, 2009, NPC amended its $600 million Second Amended and Restated Revolving Credit Agreement, which matures in November 2010, to remove a bankrupt lending bank from the facility. This amendment reduced the capacity of the facility to approximately $589 million.

On January 5, 2009, NPC entered into a new $90 million supplemental revolving credit facility. The facility has a term of 364 days, and is secured by General and Refunding Mortgage bonds. This credit facility matures in January 2010, and is in addition to NPC’s existing approximate $589 million revolving credit facility.

General and Refunding Mortgage Notes, Series V

On March 2, 2009, NPC issued and sold $500 million of its 7.125% General and Refunding Mortgage Notes, Series V due 2019. The net proceeds of the issuance were used to repay approximately $404 million of amounts outstanding under NPC’s approximate $589 million revolving credit facility, and for general corporate purposes.

General and Refunding Mortgage Notes, Series U

On January 12, 2009, NPC issued and sold $125 million of its 7.375% General and Refunding Mortgage Notes, Series U due 2014. The net proceeds of the issuance were used to repay approximately $124 million of amounts outstanding under NPC’s revolving credit facility.

Sierra Pacific Power Company

Revolving Credit Facility

On March 2, 2009, SPPC amended its $350 million Amended and Restated Revolving Credit Agreement, which matures in November 2010, to remove a bankrupt lending bank from the facility. This amendment reduced the capacity of the facility to approximately $332 million.

Conversions

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

On January 14, 2009, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007A bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Water Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Water Bonds until such time as SPPC determines to reoffer the Water Bonds to investors. These Water Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness is offset for presentation purposes.

NOTE 5. DERIVATIVES AND HEDGING ACTIVITIES

NVE, SPPC and NPC apply SFAS 133, as amended by SFAS 138, SFAS 149, SFAS 155, SFAS 157 and SFAS 161. As amended, SFAS 133 establishes accounting and reporting standards for derivatives instruments, including certain derivative instruments embedded in other contracts and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. SFAS 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchase and normal sales are accounted for under deferred energy accounting and not recorded on the Consolidated Balance Sheets at fair value.

Adoption of SFAS 161

Effective January 1, 2009, NVE and the Utilities’ adopted SFAS 161, which is intended to enhance the current disclosure framework in SFAS 133. The Statement requires the objectives for using derivative instruments be disclosed in terms of underlying risk and accounting. This Statement requires NVE and the Utilities to distinguish between instruments used for risk management and instruments used for other purposes. SFAS 161 requires disclosing the fair values of derivative instruments and their gains and losses for the period, providing more information about credit-risk related contingent features and describing the volume of their derivative activity.

Commodity Risk

The energy supply function encompasses the reliable and efficient operation of the Utilities’ generation, the procurement of all fuels and power and resource optimization (i.e., physical and economic dispatch) and is exposed to risks relating to, but not limited to, changes in commodity prices. NVE and the Utilities’ objective in using derivative instruments is to reduce exposure to energy price risk. Energy price risks result from activities that include the generation, procurement and sale of power and the procurement and sale of natural gas. Derivative instruments used to manage energy price risk from time to time may include: forward contracts, which involve physical delivery of an energy commodity; over-the-counter options with financial institutions and other energy companies, which mitigate price risk by providing the right, but not the requirement, to buy or sell energy related commodities at a fixed price; and swaps, which require the Utilities’ to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. These contracts assist the Utilities’ to reduce the risks associated with volatile electricity and natural gas markets.

Credit Risk Contingent Features

The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that the Utilities maintain their Moody’s, Fitch, and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that the Utilities’ Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require the Utilities to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to the Utilities, subject to certain caps. As of March 31, 2009, the maximum amount of collateral NPC and SPPC would be required to post under these agreements is approximately $216.5 million and $98.0 million, respectively, based on mark-to-market liability values, which are substantially based on quoted market prices. Of this amount, approximately $117.7 million and $54.6 million, respectively, would be required if NPC and SPPC are downgraded one level and additional amounts of approximately $98.9 million and $43.4 million would be required respectively if NPC and SPPC are downgraded two levels.

Determination of Fair Value

As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Risk management assets and liabilities in the recurring fair value measures table below include over-the-counter forwards, swaps and options. Total risk management assets below do not include option premiums which are not considered a derivative asset. Option premiums upon settlement are recorded in fuel and purchased power expense and are subsequently requested for recovery through the deferred energy mechanism. Option premium amounts included in risk management assets at March 31, 2009 for NVE, NPC and SPPC were as follows (dollars in millions):

	Option Premiums
	March 31, 2009						December 31, 2008
	NVE		NPC		SPPC		NVE		NPC		SPPC
Current	$	13.5	$	10.2	$	3.3	$	13.3	$	9.7	$	3.6
Non-Current		5.0		4.1		0.9		5.6		4.2		1.4
Total	$	18.5	$	14.3	$	4.2	$	18.9	$	13.9	$	5.0

Forwards and swaps are valued using a market approach that uses quoted forward commodity prices for similar assets and liabilities, which incorporates a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. Options are valued based on an income approach that uses an option pricing model that includes various inputs; such as forward commodity prices, interest rate yield curves and option volatility rates. The determination of the fair value for derivative instruments not only include counterparty risk, but also the impact of NVE and the Utilities nonperformance risk on their liabilities. Nonperformance risk is based on the credit quality of NVE and the Utilities and had an immaterial impact to the fair value of their derivative instruments.

The following table shows the fair value of the open derivative positions recorded on the Consolidated Balance Sheets of NVE, NPC and SPPC and the related regulatory assets and/or liabilities that did not meet the normal purchase and normal sales exception criteria in SFAS 133. Due to deferred energy accounting treatment under which the Utilities’ operate, regulatory assets and liabilities are established to the extent that electricity and natural gas derivative gains and losses are recoverable or payable through future rates, once realized. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement and to not recognize gains and losses on the Consolidated Statements of Income (dollars in millions):

Commodity Contracts	March 31, 2009 Fair Value Level 2 (as defined by SFAS 157) (dollars in millions)									December 31, 2008 Fair Value Level 2 (as defined by SFAS 157) (dollars in millions)
	NVE			NPC			SPPC			NVE			NPC			SPPC

Risk management assets- current	$	-		$	-		$	-		$	2.8		$	2.0		$	.8
Risk management assets- noncurrent		1.7			1.2			.5			4.4			3.2			1.2
Total risk management assets		1.7			1.2			.5			7.2			5.2			2.0

Risk management liabilities- current		412.5			300.8			111.7			313.8			222.9			90.9
Risk management liabilities- noncurrent		30.9			23.2			7.7			53.4			35.2			18.2
Total risk management liabilities		443.4			324.0			119.4			367.2			258.1			109.1

Risk management regulatory assets/liabilities – net (1)	$	(441.7	)	$	(322.8	)	$	(118.9	)	$	(360.0	)	$	(252.9	)	$	(107.1	)

(1)

When amount is negative it represents a Risk Management Regulatory Asset, when positive it represents a Risk Management Regulatory Liability. NVE and the Utilities would have incurred a loss for the period ending March 31, 2009 of $ (81.7) million, $(69.9) million, and $(11.8) million, respectively; however, in accordance with SFAS 71, NVE and the Utilities deferred these losses, which are included in the Risk management regulatory assets/liabilities amount above.

As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate. The Utilities’ cannot predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities’ open derivative positions with their counterparties and the changes in forward commodity prices. The increase in risk management liabilities as of March 31, 2009, as compared to December 31, 2008, is mainly due to unfavorable open derivative positions on natural gas options held by the Utilities’ to hedge energy price risk for their customers resulting from lower commodity prices for natural gas at March 31, 2009 relative to contract prices.

The following table shows the commodity volume of our commodity contracts:

	March 31, 2009 Commodity Volume (MMBTU) (Amounts in millions)						December 31, 2008 Commodity Volume (MMBTU) (Amounts in millions)
	NVE		NPC		SPPC		NVE		NPC		SPPC

Commodity volume assets- current		0.2		0.2		-		1.2		1.0		0 .2
Commodity volume assets- noncurrent		5.4		3.7		1.7		1.1		1.0		0 .1
Total commodity volume of assets		5.6		3.9		1.7		2.3		2.0		0.3

Commodity volume liabilities- current		122.6		89.7		32.9		119.9		86.7		33.2
Commodity volume liabilities- noncurrent		36.7		28.9		7.8		40.6		28.6		12.0
Total commodity volume of liabilities		159.3		118.6		40.7		160.5		115.3		45.2

NOTE 6. COMMITMENTS AND CONTINGENCIES

Environmental Contingencies

Nevada Power Company

NEICO

NEICO, a wholly-owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load-out facility. The site has a reclamation estimate supported by a bond of approximately $5 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. Management is continuing to evaluate various options including reclamation and sale.

Environmental Matters

NVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. As disclosed in Note 13, Commitments and Contingencies of the Notes to Financial Statements, Environmental, in the 2008 Form 10-K, NPC was subject to various environmental proceedings which were settled as of December 31, 2008. NPC continues to comply with these environmental commitments. As of March 31, 2009, environmental expenditures did not change materially from those disclosed in the 2008 Form 10-K.

Litigation Contingencies

Nevada Power Company

Peabody Western Coal Company

NPC owns an 11% interest in the Navajo Generating Station which is located in Northern Arizona and is operated by Salt River. Other participants in the Navajo Generating Station are Arizona Public Service Company, Los Angeles Department of Water and Power and Tucson Electric Power Company (together with Salt River and NPC, the “Navajo Joint Owners”). NPC also owns a 14% interest in the Mohave Generating Station which is located in Laughlin, Nevada and was operated by Southern California Edison prior to the time it became non-operational on December 31, 2005.

Royalty Claim

On October 15, 2004, the Navajo Generating Station’s coal supplier, Peabody Western Coal Co. (Peabody WC), filed a complaint against the Navajo Joint Owners in Missouri State Court in St. Louis, alleging, among other things, a declaration that the Navajo Joint Owners are obligated to reimburse Peabody WC for any royalty, tax or other obligations arising out of a lawsuit that the Navajo Nation filed against Salt River, several Peabody Coal Company entities (including Peabody WC and collectively referred to as “Peabody”) and Southern California Edison in June 1999 in the U.S. District Court for the District of Columbia (DC Lawsuit).

The operating agent for the Navajo Generating Station, Salt River, defended the suit on behalf of the Navajo Joint Owners. NPC believes Peabody WC’s claims are without merit. In July 2008, the Court dismissed all counts against NPC, two without prejudice to their possible refiling at a later date. NPC is unable to predict whether any liability may arise from any of these matters, including from the ultimate outcome of the DC Lawsuit.

NPC is not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo Generating Station and the Mohave Generating Station. The DC Lawsuit consists of various claims relating to the renegotiations of coal royalty and lease agreements and alleges, among other things, that the defendants obtained a favorable coal royalty rate for the lease agreements under which Peabody mines coal for both the Navajo Generating Station and the Mohave Generating Station by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. The DC Lawsuit seeks $600 million in damages, treble damages, and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo tribal lands arising out of the primary coal lease. In July 2001, the U.S. District Court dismissed all claims against Salt River. The action was stayed since October 5, 2004 until March, 2008 when the U.S. District Court referred pending discovery related motions to a Magistrate judge. Those discovery motions have now been resolved and factual discovery is taking place. The parties have committed to providing proposed recommendations for future proceedings to the Court by May 27, 2009.

Sierra Pacific Power Company

Farad Dam

SPPC sold four hydro generating units, (10.3 MW total capacity), located in Nevada and California, for $8 million to TMWA in June 2001. The Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million. Under the terms of the contract with TMWA, SPPC is not entitled to receive the proceeds of sale relating to Farad unless and until it has reconstructed the Farad facility in a manner reasonably acceptable to TMWA or SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (collectively, the “Insurers”) for the Farad flume and Farad Dam. In December 2003, SPPC sued the Insurers in the U.S. District Court for the District of Nevada on a coverage dispute relating to potential rebuild costs for Farad Dam. The case went to trial before the Court in April 2008. On September 30, 2008, the Court ruled that SPPC was not time barred from reconstructing Farad Dam, and has coverage for the full rebuild costs, subject to coverage sub-limits set forth in the insurance policies. The Court further ruled that SPPC is entitled to recover $4 million for costs incurred to date on Farad Dam and that SPPC shall have three years to rebuild the dam from the date of the Court’s decision. In the event Farad Dam is not rebuilt, the Court determined SPPC would be entitled to actual cash value of approximately $1.3 million. SPPC has requested the court to reconsider the cash value to reflect rebuild costs and the Insurers opposed. Parties are awaiting a decision from the Court. The Insurers time to file an appeal on the Court’s decision has been suspended pending the Court’s determination on the cash value reconsideration.

Other Legal Matters

NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal matters, none of which, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations or cash flows.

NOTE 7. EARNINGS PER SHARE (NVE)

The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans and the non-employee director stock plan. Due to the net loss for the three months ended March 31, 2009, these items are anti-dilutive and diluted EPS for the period is computed using the weighted average number of shares outstanding before dilution.

Emerging Issues Task Force, Participating Securities and the Two-Class Method under SFAS 128, (EITF 03-6) requires companies to use the “two-class” method to calculate basic EPS, and the “if-converted” method to calculate diluted EPS if the result was dilutive.

The following table outlines the calculation for EPS:

	Three months ended March 31,
	2009			2008
Basic EPS
Numerator ($000)

Net income (loss)	$	(22,244	)	$	24,058

Denominator
Weighted average number of common shares outstanding		234,331,044			233,836,234

Per Share Amounts

Net income (loss) per share – basic	$	(0.09	)	$	0.10

Diluted EPS
Numerator ($000)

Net income (loss)	$	(22,244	)	$	24,058

Denominator (1)
Weighted average number of shares outstanding before dilution		234,331,044			233,836,234
Stock options		-			60,750
Non-Employee Director stock plan		-			56,313
Restricted Shares		-			1,311
Performance Shares		-			367,364
		234,331,044			234,321,972

Per Share Amounts

Net income (loss) per share – diluted	$	(0.09	)	$	0.10

(1) The denominator does not include stock equivalents resulting from the options issued under the nonqualified stock option plan due to conversion prices being higher than market prices for all periods. Under this plan, 1,072,678 and 909,795 shares for the periods ending March 31, 2009 and 2008, respectively, would be included if the conditions for conversions were met.

NOTE 8. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

A summary of the components of net periodic pension and other postretirement costs for the three months ended March 31 follows. This summary is based on a December 31, 2008 measurement date for 2009 and a September 30, 2007 measurement date for 2008 (dollars in thousands):

NVE, Consolidated
	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008

Service cost	$	4,709		$	6,022		$	577		$	565
Interest cost		11,036			10,790			2,637			2,218
Expected return on plan assets		(9,290	)		(12,661	)		(1,508	)		(2,032	)
Amortization of prior service cost		(448	)		408			(171	)		(748	)
Amortization of net (gain)/loss		6,894			772			1,273			890
Amortization of Transition Obligation		-			-			-			-
Settlement (gain)/loss		-			-			84			-

Net periodic benefit cost	$	12,901		$	5,331		$	2,892		$	893

NPC
	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008

Service cost	$	2,393		$	3,550		$	310		$	295
Interest cost		5,270			5,353			607			555
Expected return on plan assets		(4,462	)		(6,067	)		(509	)		(680	)
Amortization of prior service cost		(433	)		363			289			179
Amortization of net (gain)/loss		3,298			375			287			218
Amortization of Transition Obligation		-			-			-			-
Settlement (gain)/loss		-			-			19			-

Net periodic benefit cost	$	6,066		$	3,574		$	1,003		$	567

SPPC
	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008

Service cost	$	2,061		$	2,178		$	251		$	253
Interest cost		5,471			5,086			2,014			1,626
Expected return on plan assets		(4,580	)		(6,265	)		(977	)		(1,317	)
Amortization of prior service cost		(26	)		52			(465	)		(931	)
Amortization of net (gain)/loss		3,425			336			978			657
Amortization of Transition Obligation		-			-			-			-
Settlement (gain)/loss		-			-			65			-

Net periodic benefit cost	$	6,351		$	1,387		$	1,866		$	288

In 2008, in accordance with SFAS 158, NVE, NPC and SPPC recorded additional pension costs, relating to the elimination of the early measurement date, to retained earnings of $5.3 million, $3.6 million and $1.4 million, respectively, before taxes. Additionally, in 2008 in accordance with SFAS 158, NVE, NPC and SPPC recorded additional post retirement benefit costs relating to the elimination of the early measurement date to retained earnings of $1.0 million, $0.6 million and $0.4 million, respectively, before taxes. These amounts represent the expense attributable to the three month period from September 30, 2007 to December 31, 2007. NVE has changed the measurement date for its benefit plans from September to December 31, which coincides with NVE’s fiscal year end.

In the first quarter ended March 31, 2009, NVE made a contribution to the pension plan in the amount of $20 million, with $13.5 million allocated to the 2008 plan year and the remainder to the 2009 plan year. At the present time, it is anticipated that there will be further contributions made to both the pension and other postretirement benefits plans in 2009, however the amounts will not be known until asset values and market conditions can be evaluated at the time of the contribution.

NOTE 9. DIVIDENDS

On February 5, 2009, NVE’s BOD declared a quarterly cash dividend of $0.10 per share which was paid in March 2009 to common shareholders of record on March 3, 2009. On April 30, 2008, NVE’s Board of Directors declared a quarterly cash dividend of $0.10 per share to common shareholders of record on June 2, 2009, payable on June 17, 2009.

NOTE 10. SUBSEQUENT EVENTS

Sierra Pacific Power Company – California Asset Sale

In April 2009, SPPC entered into an agreement to sell its California electric distribution and generation assets to California Pacific Electric Company (the California Asset Sale). Based on the terms of the purchase agreement, SPPC will receive proceeds that include a premium on current net rate base assets as of the closing date, plus a working capital adjustment. Net rate base assets include utility plant in service, net and deferred credits and other liabilities. Such proceeds are expected to be above the current book value of the related net assets. The sale is expected to close in 2010, and is subject to obtaining necessary federal and state regulatory approvals. In accordance with SFAS No. 144, the related assets qualify as a sale of assets and will be reported separately as “Assets Held for Sale” in the balance sheet at June 30, 2009.

Below are the major classes of assets and liabilities related to the California Asset Sale (dollars in millions):

Assets	March 31, 2009		December 31, 2008

Utility Plant in Service	$	185.1	$	183.2

Less: Accumulated depreciation	$	66.7	$	65.0
Utility Plant in Service, net	$	118.5	$	118.2

Construction work-in-progress	$	6.3	$	5.5
Other current assets	$	7.1	$	6.8
Deferred Charges	$	3.5	$	3.0

Assets	$	135.4	$	133.5

Liabilities

Deferred Credits and Other Liabilities	$	14.9	$	15.1

Liabilities	$	14.9	$	15.1

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

Forward-Looking Statements and Risk Factors

The information in this Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.

Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify those statements that are forward-looking. These statements are based on management’s beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of NVE, NPC or SPPC; (NPC and SPPC are collectively referred to as the Utilities) to differ materially from those contemplated in any forward-looking statement include, among others, the following:

(1)

economic conditions both nationwide and regionally, including availability and cost of credit, inflation rates, monetary policy, unemployment rates, customer bankruptcies, weaker housing markets, a decrease in tourism, particularly in southern Nevada, and cancelled or deferred hotel construction projects, which could affect customer collections, customer demand and usage patterns;

(2)	changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities, including the effect of weaker housing markets and increased unemployment, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

(3)

unfavorable or untimely rulings in rate or other cases filed or to be filed by the Utilities with the PUCN, including the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, and deferred natural gas costs recorded by SPPC for its gas distribution business;

(4)

the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their requirements for working capital, including amounts necessary for construction and acquisition costs and other capital expenditures, as well as to finance deferred energy costs, particularly in the event of: continued volatility in the global credit markets, unfavorable rulings by the PUCN, untimely regulatory approval for utility financings, and/or a downgrade of the current debt ratings of NVE, NPC or SPPC;

(5)	financial market conditions, including the effect of recent volatility in financial and credit markets, changes in availability and cost of capital either due to market conditions or as a result of the Utilities’ credit ratings, or interest rate fluctuations;

(6)

unseasonable weather, drought, threat of wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, could seriously impact the Utilities’ ability to procure adequate supplies of fuel or purchased power and the cost of procuring such supplies, and could affect the amount of water available for electric generating plants in the Southwestern U.S., and could have other adverse effects on our business;

(7)

whether the Utilities will be able to continue to obtain fuel and power from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands (for example, due to unseasonably hot weather), physical availability, sharp increases in the prices for fuel (including increases in long term transportation costs) and/or power or a ratings downgrade;

(8)	further increases in the unfunded liability or changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension plan, which can affect future funding obligations, costs and pension plan liabilities;

(9)	whether the Utilities can procure sufficient renewable energy sources in each compliance year to satisfy the Nevada Portfolio Standard;

(10)

construction risks, such as delays in permitting, changes in environmental laws, difficulty in securing adequate skilled labor, cost and availability of materials and equipment (including escalating costs for materials, labor and environmental compliance due to timing delays and other economic factors which may affect vendor access to capital), equipment failure, work accidents, fire or explosions, business interruptions, possible cost overruns, delay of in-service dates, and pollution and environmental damage;

(11)	changes in environmental laws or regulations, including the imposition of limits on emissions of carbon dioxide from electric generating facilities, which could significantly affect our existing operations as well as our construction program;

(12)

wholesale market conditions, including availability of power on the spot market and the availability to enter into gas financial hedges with creditworthy counterparties, which affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;

(13)	whether the Utilities will be able to continue to pay NVE dividends under the terms of their respective financing and credit agreements and limitations imposed by the Federal Power Act;

(14)

the discretion of NVE's Board of Directors regarding NVE's future common stock dividends based on the Board of Directors periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions in NVE's and the Utilities' agreements;

(15)	the effect that any future terrorist attacks, wars, threats of war or epidemics may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the national economy in general;

(16)	changes in tax or accounting matters or other laws and regulations to which NVE or the Utilities are subject;

(17)	the effect of existing or future Nevada, California or federal legislation or regulations affecting electric industry restructuring, including laws or regulations which could allow additional customers to choose new electricity suppliers or change the conditions under which they may do so;

(18)

changes in the business or power demands of the Utilities’ major customers, including those engaged in gold mining or gaming, which may result in changes in the demand for services of the Utilities, including the effect on the Nevada gaming industry of the opening of additional gaming establishments in California, other states and internationally;

(19)	employee workforce factors, including changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, and potential difficulty in recruiting new talent to mitigate losses in critical knowledge and skill areas due to an aging workforce; and

(20)	unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs.

Other factors and assumptions not identified above may also have been involved in deriving these forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. NVE, NPC and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements.

NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTS

In reviewing the agreements filed as exhibits to this Quarterly Report on Form 10-Q, please remember that they are filed to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about NVE, the Utilities or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:

·	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate;

·	have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

·	may apply standards of materiality in a way that is different from what may be viewed as material to investors; and

·	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

EXECUTIVE OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations of NVE and its two primary subsidiaries, NPC and SPPC, collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to NVE and the Utilities collectively), and includes the following:

●	For each of NVE, NPC and SPPC:

	§	Results of Operations

	§	Analysis of Cash Flows

	§	Liquidity and Capital Resources

●	Regulatory Proceedings (Utilities)

NVE’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas. The Utilities are public utilities engaged in the generation, transmission, distribution and sale of electricity and, in the case of SPPC, sale of natural gas. Other segment operations consist mainly of unregulated operations and the holding company operations. The Utilities are the principal operating subsidiaries of NVE and account for substantially all of NVE’s assets and revenues. NVE, NPC and SPPC are separate filers for SEC reporting purposes and as such this discussion has been divided to reflect the individual filers (NVE, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.

NVE incurred a net loss of $22.2 million for the three months ended March 31, 2009 compared to net income of $24.1 million for the same period in 2008. Consolidated gross margin increased for the quarter by $7.7 million primarily due to increased rates as a result of SPPC's 2007 GRC, effective July 1, 2008; however, earnings decreased primarily due to increased other operating expenses, maintenance expense and depreciation, some of which are costs related to the purchase of the Higgins Generating Station and the construction of the Clark Peaking Units, which are not currently in rates but are being requested in NPC’s current GRC, and lower revenues as a result of milder weather. Other items which contributed to the decrease in earnings include higher interest charges and a decrease in AFUDC and other income. Interest charges increased due to the issuances of new debt to fund significant capital expenditures, which is not currently being recovered in NPC’s cost of capital. AFUDC decreased as a result of a decrease in construction activity and the completion of major capital projects in 2008. Other income decreased due to income earned in 2008 for the settlement with Calpine and reinstatement of previously disallowed costs related to Pinon Pine.

The Utilities’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter. The variations in energy usage by the Utilities’ customers due to varying weather and other energy usage patterns necessitates a continual balancing of loads and resources and purchases and sales of energy under short and long term contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities. Additionally, the recovery of purchased power and fuel costs, and other costs, on a timely basis, and the ability to earn a fair return on investments are essential to the operating and financial performance of the Utilities.

2009 Current Matters

The economy in Nevada has been adversely affected by the recession facing the U.S. and the global economy, resulting in decelerated growth compared to prior years when Nevada was experiencing high growth. Tourism and gaming remain southern Nevada’s leading industries, driving construction activity, the housing market and employment in the region, and together comprising one of NPC’s largest classes of customers. Management continues to monitor hotel room additions and the hotel/motel occupancy rate in Las Vegas, which has decreased approximately 6.9% as of February 28, 2009 from a year ago. Additionally, the unemployment rate in Nevada is currently at 10.3% compared to 5.4% in 2008. The expected room growth rate for 2009 is 9.1%, concentrated primarily in Project City Center, which is developed and jointly owned by MGM Mirage, and 2.7% for 2010. Gaming properties in southern Nevada are experiencing financial difficulties, including meeting debt payments, bankruptcies and delays or termination of construction projects which may further decrease the projected growth in rooms or offset any increases. Other economic conditions affecting Nevada include the national decrease in real estate market activity which makes it more difficult for individuals and businesses to sell their properties in order to relocate to Nevada.

As the Utilities’ service territories transition from a time of high growth to a much slower growth rate, management continues to place a significant emphasis on modifying our business strategies to reflect the foregoing economic indicators and their effect on various factors including, but not limited to:

·	customer growth;

·	load factors;

·	future capital projects and capital requirements;

·	managing operating and maintenance expenses within projected revenue growth;

·	our liquidity and ability to access capital markets;

·	collections on accounts receivable; and

·	counterparty risk.

Upon evaluation of the factors above, the Company has reduced cash requirements for capital expenditures by approximately $120 million to $145 million for 2009 for total estimated cash requirements of $800 million to $775 million for the current year. The current recession, as well as recent volatility in the global credit and financial markets, has created an unprecedented level of uncertainty regarding future business conditions. While management expects to maintain this process of continual reevaluation for the foreseeable future, it is not possible to predict how long the economic recession will continue or what its long-term effect will be on the economy in general or on our financial position, cash flows or results of operations in particular.

2009 and Beyond

In 2009 and beyond, management will remain focused on implementing the three part strategy of the energy supply plan which includes energy efficiency and conservation programs, purchase and development of renewable energy projects and expansion of traditional generating capacity and transmission capability to move energy throughout the state. Additional key objectives include management of energy risk, management of environmental matters, management of regulatory filings and to further broaden access to capital.

Energy Efficiency and Conservation Programs

A part of our strategy to reduce dependence on purchased power is to manage our resources against our load requirements with energy efficiency and conservation programs, also known as DSM programs. NPC and SPPC have designed a portfolio of cost effective DSM programs that allow every customer to take advantage of savings from energy efficiency measures. DSM programs are marketed across all segments of customer classes (residential, commercial, public and low income).

The Utilities are planning to invest between $45 million and $60 million in DSM programs in 2009. The final amount will be determined by numerous factors, such as the economy, the impact of federal government stimulus legislation, performance of existing and new programs and many other factors.

Purchase and Development of Renewable Energy Projects

The Utilities have embarked on a strategy to invest in renewable energy that, along with purchased power contracts and an increase in DSM programs, will enhance the opportunity for the Utilities to fully meet the Portfolio Standard as required by Nevada law. The Utilities' compliance with the Portfolio Standard is dependent on the availability of renewables.

In 2009 and 2010, the Utilities are required to obtain an amount of PECs equivalent to 12% of their total retail energy from renewables. In April 2009, the Utilities filed their annual compliance report which reported compliance with the standard; however, the PUCN has not yet ruled on the filing. The Utilities continue to develop and explore sources for renewable energy. NPC’s current capital budget includes investing approximately $110 million for renewable energy projects through 2011.

Expansion of Traditional Generating and Transmission Capacity

In 2009, NPC continues the construction of the 500 MW (nominally rated) natural gas generating station at the existing Harry Allen Generating Station, which is expected to be operational by summer 2011. Currently, the expansion at the Harry Allen Generating Station is the only generating project under construction. The Utilities do not anticipate any new construction or purchases of generating facilities in the near future. In July 2009, NPC will file its triennial 2009 IRP with the PUCN, which will include the construction of the ON Line.

Management of Energy Risk

The Utilities have implemented a prudent strategy of piecemeal procurements transacted in regular intervals and completed before the start of the peak summer season. This provides the Utilities with ample opportunities for optimizing their portfolio on a rolling basis in anticipation of changes in system conditions, load forecasts, and regional energy market fundamentals. The Utilities also coordinate the planned maintenance schedules of their owned generating plants and transmission facilities with expectations of start dates of new generating plants or purchased power contracts.

Management of Environmental Matters

Environmental laws affect existing generating facilities and current and prospective capital construction projects. Such effects include but are not limited to increased costs, closure of existing facilities, mandated equipment upgrades, and termination of the construction of facilities. Environmental laws already affect the energy we buy; as discussed above under Purchase and Development of Renewable Energy Projects.

A key objective for the Utilities in 2009 will be to enhance and maintain our energy infrastructure investments in ways that meet customer demand for reliable energy in an efficient and environmentally responsible manner. The Utilities believe that a diverse and balanced portfolio of energy resources represents opportunity for reliability and cost control, yet are also mindful of our overriding environmental responsibility. The Utilities are committed to making technology choices with a primary focus on limiting emissions and optimizing our investments so that prices remain competitive.

Management of Regulatory Filings

As is the case with most regulated entities, the Utilities are frequently involved in various regulatory proceedings. The Utilities are required to file for quarterly rate adjustments to provide recovery of their fuel and purchased power costs. They are also required to file rate cases every three years to adjust general rates that include their cost of service and return on investment in order to more closely align earned returns with those allowed by regulators. Furthermore, the Utilities are required to file a triennial IRP which is a comprehensive plan that considers customer energy requirements and proposes the resources to meet that requirement. Resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes. Between IRP filings, the Utilities may seek PUCN approval for modifications to their resource plans and for power purchases. The Utilities incur costs for such items as deferred fuel and purchased power costs, operations and maintenance and capital projects; however, as costs are not recovered through rates until approved by regulators, the timing between costs incurred and recovery is considered regulatory lag. In some cases, the loss due to regulatory lag is not recovered. As such, timely and accurate filings of these various rate cases is essential to the Utilities’ operating and financial performance as it reduces regulatory lag, which has a direct effect on the cash flows, and in some cases earnings, of the Utilities. Furthermore, the timing of the filings and subsequent decisions can affect the timing of construction and thus the economic benefits. As a result, the Utilities file quarterly BTER updates to minimize exposure to changes in fuel and purchased power expense and file amendments to IRP’s as changes in resource needs occur.

Significant filings pending regulatory outcome in 2009 include NPC’s GRC and SPPC’s California GRC. For a more detailed discussion of the filing requests, see Note 3, Regulatory Actions of the Notes to Financial Statements.

Further Broaden Access to Capital

A significant focus in 2009 will again be to generate sufficient cash from operations to meet operating needs and contribute to capital projects by managing recovery of deferred fuel and purchased power costs, reducing regulatory lag in recovery of costs and controlling costs.

Commodity prices and the amount of capital required for construction projects are projected to be significantly lower in 2009 compared to 2008. As a result, for the remainder of 2009, the Utilities believe they will be able to meet such financial obligations with a combination of internally generated funds and the use of the Utilities’ revolving credit facilities. However, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel and purchased power in a timely manner, the Utilities may need to issue additional debt to support their operating costs or further delay capital expenditures, and NVE may need to issue additional equity securities. As such, maintaining sufficient liquidity through the use of the Utilities’ revolving credit facilities and maintaining our ability to issue new debt or equity securities on favorable terms continues to be a significant focus in 2009.

NV ENERGY, INC.

RESULTS OF OPERATIONS

NV Energy, Inc. (Holding Company) and Other Subsidiaries

NVE (Holding Company)

The Holding Company’s (stand alone) operating results included approximately $9.4 million and $10.4 million of long-term debt interest costs for the three months ended March 31, 2009 and 2008, respectively. The decrease in interest costs for the three months ended March 31, 2009 as compared to the same period in 2008 was primarily due to debt repurchase in 2008. See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2008 Form 10-K, for further discussion of the debt repurchase.

Other Subsidiaries

Other Subsidiaries of NVE, except for NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.

NV Energy, Inc. (Consolidated)

See Executive Overview, Overview of Major Factors Affecting Results of Operations for NVE Consolidated.

ANALYSIS OF CASH FLOWS

Cash flows increased during the three months ended March 31, 2009 compared to the same period in 2008 primarily due to an increase in cash from financing activities and to a lesser extent a decrease in cash from investing activities, partially offset by a decrease in cash from operating activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to lower revenues as a result of milder weather and to a lesser extent, changes in customer usage patterns. Also contributing to the decrease in cash from operating activities was an increase in costs for operations and maintenance costs for generating facilities, the funding of approximately $20 million for pension plans, prepayments for land leases, a decrease in accounts payable from December 31, 2008 for energy and other suppliers, the timing of interest payments and, in 2008, NPC received a significant prepayment for transmission services. Partially offsetting these decreases was reduced spending for regulatory activities.

Cash Used By Investing Activities. Cash used by investing activities decreased slightly due to reduced construction activity.

Cash From Financing Activities. Cash from financing activities increased primarily due to the issuance of approximately $625 million in new debt, partially offset by payments on the revolving credit facility and increase in dividends to common shareholders.

LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)

Overall Liquidity

NVE’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC. The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and, in the case of SPPC, natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.

As of March 31, 2009, NVE, NPC and SPPC had cash on hand of approximately $2.6 million, $81.6 million, $28.9 million, respectively. NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, NVE and the Utilities may issue debt up to $281.5 million, on a consolidated basis, which includes the use of approximately $268.0 million of the Utilities’ revolving credit facilities. See Factors Affecting Liquidity, Ability to Issue Debt, below. NVE and the Utilities anticipate with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that cash on hand, internally generated funds and the ability to issue debt, which includes the use of the Utilities’ revolving credit facility, will be sufficient to meet short-term operating costs. However, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less. In order to maintain sufficient liquidity, NVE and the Utilities may be required to further delay capital expenditures, re-finance debt or issue equity.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter and the Utilities may not be able to fully utilize the availability on their revolving credit facilities. NVE and the Utilities are projecting that their ability to issue debt will increase in the second and third quarter of 2009, as the Utilities’ operating income typically increases during this time period, and new rates as a result of NPC’s GRC are expected to be in effect beginning July 1, 2009.

NVE and the Utilities do not have significant debt maturities in 2009 or 2010 other than their revolving credit facilities. As of April 30, 2009, NPC and SPPC had $18.3 million and $206.1 million, respectively outstanding on their revolving credit facilities including letters of credit. The Utilities’ long-term credit facilities expire in November 2010, and NPC’s Supplemental Revolving Credit Facility expires in January 2010.

There have been no changes to the credit ratings of NVE and the Utilities in the first quarter of 2009, other than DBRS’ election to discontinue coverage on a majority of their U.S. clients (see Credit Ratings, below). However, disruptions in the banking and capital markets not specifically related to NVE or the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

NVE (stand-alone) has approximately $21.4 million of debt service obligations remaining for 2009, which it intends to pay through dividends from subsidiaries. (See Factors Affecting Liquidity-Dividends from Subsidiaries below).

During the three months ended March 31, 2009, there were no material changes to contractual obligations as set forth in NVE’s 2008 Form 10-K. See NPC’s and SPPC’s respective sections for changes in their contractual obligations.

Factors Affecting Liquidity

Effect of Holding Company Structure

As of March 31, 2009, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: $63.7 million of its unsecured 7.803% Senior Notes due 2012; $191.5 million of its unsecured 6.75% Senior Notes due 2017; and $230 million of its unsecured 8.625% Senior Notes due 2014.

Due to the holding company structure, NVE’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors. Therefore, NVE’s debt obligations are effectively subordinated to all existing and future claims of the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.

As of March 31, 2009, NVE, NPC, SPPC and their subsidiaries had approximately $5.5 billion of debt and other obligations outstanding, consisting of approximately $3.6 billion of debt at NPC, approximately $1.4 billion of debt at SPPC and approximately $485 million of debt at the holding company and other subsidiaries. Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay.

In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. As a result of the Utilities’ credit ratings on their senior secured debt at investment grade by S&P and Moody’s, these restrictions are suspended and are no longer in effect so long as the debt remains investment grade by both rating agencies. In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to NVE could be jeopardized.

In the first quarter of 2009, NPC and SPPC paid dividends to NVE of $22 million and $108.8 million, respectively. On April 30, 2009, NPC and SPPC declared a $40 million and $20 million dividend, respectively, to NVE.

Credit Ratings

NVE, NPC and SPPC are currently rated by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. DBRS is no longer covering NVE and the Utilities. The senior secured debt of NPC and SPPC is rated investment grade by these three rating organizations. As of March 31, 2009, the ratings are as follows:

		Rating Agency
		Fitch	Moody’s	S&P
NVE	Sr. Unsecured Debt	BB-	Ba3	BB
NPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*
NPC	Sr. Unsecured Debt	BB	Not rated	BB+
SPPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*

*Investment grade

S&P’s and Moody’s rating outlook for NVE, NPC and SPPC is Stable. Fitch’s rating outlook for NVE, NPC and SPPC is Positive.

A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.

Ability to Issue Debt

NV Energy, Inc.

Certain debt of NVE (holding company) places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four quarter period on a pro forma basis is at least 2 to 1.

Additionally, under the terms of the debt, NPC and SPPC are permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities. As of March 31, 2009, NPC had $15.3 million of letters of credit outstanding and SPPC had approximately $200 million borrowed and $17.1 million of letters of credit outstanding against its revolving credit facility; therefore, the remaining combined availability is $268 million. If however, the Utilities were to receive a credit rating downgrade and were required to post collateral, as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of availability under the revolving credit facilities would be further reduced.

Under these covenant restrictions, as of March 31, 2009, NVE (consolidated) would be allowed to incur up to $281.5 million of additional debt, which includes $268 million of combined usage under NPC’s and SPPC’s revolving credit facilities.

If the applicable series of debt is upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes remain investment grade by both Moody’s and S&P (see Credit Ratings above).

Nevada Power Company

Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and revolving credit facility agreements, and the terms of certain NVE debt.

On February 4, 2009, the PUCN approved NPC’s request for financing authority to issue up to $1.25 billion of long-term debt securities over a two-year period ending December 31, 2010; ongoing authority to maintain a revolving credit facility of up to $1.3 billion, and authority to refinance up to approximately $471 million of long-term debt securities.

NPC's $589 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and its supplemental Revolving Credit Agreement, dated January 5, 2009, each contain two financial maintenance covenants. The first requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires NPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of March 31, 2009, NPC was in compliance with these covenants. Based upon estimated interest expense, in order to maintain compliance with these covenants, NPC is limited to borrowing $314 million, which is less than the unused balance on its revolving credit facilities of $663.8 million.

All other financial covenants contained in NPC’s revolving credit facility agreement and its financing agreements are suspended, as NPC’s senior secured debt is rated investment grade. However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations on indebtedness under these covenants.

Furthermore, NPC may be subject to NVE’s cap on additional consolidated indebtedness. See NVE’s Ability to Issue Debt. As of March 31, 2009, NPC’s own covenant restriction of $314 million is less restrictive than NVE’s cap on additional consolidated indebtedness of $281.5 million. As such, NPC is limited by NVE’s cap on additional indebtedness of $281.5 million, which includes the combined usage of the Utilities’ revolving credit facilities of $268.0 million.

Ability to Issue General and Refunding Mortgage Securities

To the extent that NPC has the ability to issue debt under the most restrictive covenants in its or NVE’s financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under NPC’s General and Refunding Mortgage Indenture.

The Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of March 31, 2009, $4 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $499.3 million of General and Refunding Mortgage Securities as of March 31, 2009. That amount is determined on the basis of:

1.	70% of net utility property additions;
2.	the principal amount of retired General and Refunding Mortgage Securities; and/or
3.	the principal amount of first mortgage bonds retired after October 2001.

Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

NPC also has the ability to release property from the lien of the mortgage indenture on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of its Indenture, it will reduce the amount of securities issuable under the Indenture.

Sierra Pacific Power Company

Ability to Issue Debt

SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt.

As of March 31, 2009, SPPC had approximately $495 million of PUCN financing authority, which expires on December 31, 2009.

SPPC's $332 million Amended and Restated Revolving Credit Agreement dated November 2005 contains two financial maintenance covenants. The first requires SPPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires SPPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of March 31, 2009, SPPC was in compliance with these covenants. In order to maintain compliance with these covenants, SPPC is limited to borrowing $653 million, which can consist of additional draws against its revolving credit facilities or additional indebtedness.

All other financial covenants contained in SPPC’s revolving credit facility and financing agreements are suspended, as SPPC’s senior secured debt is rated investment grade. However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations on indebtedness under these covenants.

Furthermore, SPPC may be subject to NVE’s cap on additional consolidated indebtedness. See NVE’s Ability to Issue Debt. As of March 31, 2009, SPPC’s own covenant restriction of $652.7 million is less restrictive than NVE’s cap on additional consolidated indebtedness of $281.5. As such, SPPC is limited by NVE’s cap on additional indebtedness of $281.5 million, which includes the combined usage of the Utilities’ revolving credit facilities of $268.0 million.

Ability to Issue General and Refunding Mortgage Securities

To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its or NVE’s financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under SPPC’s General and Refunding Mortgage Indenture (“Indenture”).

The Indenture creates a lien on substantially all of SPPC’s properties in Nevada and California. As of March 31, 2009, $1.7 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $613.1 million of General and Refunding Mortgage Securities as of March 31, 2009. That amount is determined on the basis of:

1.	70% of net utility property additions;
2.	the principal amount of retired General and Refunding Mortgage Securities; and/or
3.	the principal amount of first mortgage bonds retired after October 2001.

Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

SPPC also has the ability to release property from the lien of the mortgage indenture on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of its Indenture, it will reduce the amount of securities issuable under the Indenture.

Cross Default Provisions

None of the Utilities’ financing agreements contains a cross-default provision that would result in an event of default by that Utility upon an event of default by NVE or the other Utility under any of their respective financing agreements. Certain of NVE’s financing agreements, however, do contain cross-default provisions that would result in event of default by NVE upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of NVE and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event, during which time NVE or the Utilities may rectify or correct the situation before it becomes an event of default.

Energy Supplier Matters

With respect to NPC’s and SPPC’s contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the WSPP agreement, an industry standard contract that NPC and SPPC use as members of the WSPP. The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC and SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of March 31, 2009 for all suppliers continuing to provide power under a WSPP agreement would approximate a $186.6 million payment or obligation to NPC. No amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception of SFAS 133, and as such, are not required to be mark-to-market on the balance sheet. Refer to Note 5, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements for further discussion.

Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counter-parties require payment in advance of delivery.

Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has one transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. For this counterparty, if NPC’s senior secured ratings from both Moody’s and S&P are below investment grade, the maximum collateral amount would be $46.1 million. If NPC’s senior unsecured rating from both Moody’s and S&P are below investment grade, the maximum collateral requirement would be $11.5 million.

Financial Gas Hedges

The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that the Utilities maintain their Moody’s and S&P senior unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that the Utilities senior unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require the Utilities to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to the Utilities, subject to certain caps. As of March 31, 2009, the maximum amount of collateral the Utilities would be required to post under these agreements is approximately $313.1 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $171.3 million would be required if the Utilities are downgraded one level and an additional amount of approximately $141.8 million would be required if the Utilities are downgraded two levels.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC incurred a net loss of $35.2 million for the three months ended March 31, 2009 compared to net income of $8.0 million for the same period in 2008.

As of March 31, 2009, NPC had paid $22 million in dividends to NVE. On April 30, 2009, NPC declared an additional dividend of $40 million.

Gross margin is presented by NPC in order to provide information that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is a key factor utilized by management in its analysis of its business.

NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which NPC calculates as operating revenues less fuel and purchased power costs, provides a measure of income available to support the other operating expenses of NPC. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect NPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

The components of gross margin for the three months ended March 31 were (dollars in thousands):

	Three Months Ended March 31,
	2009		2008		Change from Prior Year
Operating Revenues:
Electric	$	436,529	$	469,172		-7.0	%

Energy Costs:
Fuel for power generation		154,062		164,021		-6.1	%
Purchased power		88,206		93,750		-5.9	%
Deferral of energy costs - net		38,190		45,775		-16.6	%
	$	280,458	$	303,546		-7.6	%


Gross Margin	$	156,071	$	165,626		-5.8	%

Gross margin decreased in the first quarter of 2009, compared to the same period in 2008, primarily due to a decrease in customer usage primarily as a result of milder winter weather, and the termination of various transmission service agreements. Partially offsetting these decreases was a slight increase in average customer growth.

The causes for significant changes in specific lines comprising the results of operations for NPC for the respective years ended are provided below (dollars in thousands except for amounts per unit).

	Three Months Ended March 31,
					Change from
	2009		2008		Prior Year
Electric Operating Revenues ($000):
Residential	$	191,370	$	205,378		-6.8	%
Commercial		96,794		104,512		-7.4	%
Industrial		128,039		133,013		-3.7	%
Retail revenues		416,203		442,903		-6.0	%
Other		20,326		26,269		-22.6	%
Total Revenues	$	436,529	$	469,172		-7.0	%

Retail sales in thousands
of MWhs		4,121		4,294		-4.0	%

Average retail revenue per MWh	$	101.00	$	103.14		-2.1	%

NPC’s retail revenues decreased for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to decreases in customer usage primarily as a result of milder winter weather and, to a lesser extent, changes in customer usage patterns, as well as decreases in retail rates. Retail rates decreased as a result of NPC’s various BTER quarterly adjustments and Deferred Energy Cases (see Note 3, Regulatory Actions of the Notes to the Financial Statements in the 2008 Form 10-K). Slightly offsetting these decreases were increases to the average number of residential, commercial and industrial customers of 0.6%, 0.4% and 3.3%, respectively.

Electric Operating Revenues – Other decreased for the three months ended March 31, 2009, compared to the same period in 2008. The decrease is primarily due to the termination of several transmission agreements, including a transmission agreement related to the Higgins Generating Station which was purchased in October 2008.

Energy Costs

Energy Costs include Fuel for Generation and Purchased Power. Energy costs are dependent upon several factors which may vary by season or period. As a result, NPC’s usage and average cost per MWh of fuel for generation versus purchased power to meet demand can vary significantly. Factors that may affect energy costs include, but are not limited to:

●		Weather
●		Generation efficiency
●		Plant outages
●		Total system demand
●		Resource constraints
●		Transmission constraints
●		Natural gas constraints
●		Long-term contracts; and
●		Mandated power purchases

	Three Months Ended March 31,
					Change from
	2009		2008		Prior Year

Energy Costs	$	242,268	$	257,771		-6.0	%
Total System Demand (MWhs)		4,342		4,533		-4.2	%
Average cost per MWh	$	55.80	$	56.87		-1.9	%

Energy costs, total system demand and the average cost per MWh decreased for the three months ended March 31, 2009, as compared to 2008. Energy costs and the average cost per MWh decreased primarily due to a decline in natural gas prices and an increase in self generation which was more economical than purchased power, partially offset by an increase in the settlement costs for hedging instruments. For the three months ended March 31, 2009, self generation represented approximately 83% of total system demand compared to approximately 74% for the same period in 2008. Total system demand decreased primarily due to a decrease in customer usage as a result of milder weather and a change in customer usage patterns.

Fuel For Power Generation

	Three Months Ended March 31,
					Change from
	2009		2008		Prior Year

Fuel for Power Generation	$	154,062	$	164,021		-6.1	%

Thousands of MWhs generated		3,607		3,337		8.1	%
Average cost per MWh of
Generated Power	$	42.71	$	49.15		-13.1	%

Fuel for power generation and the average cost per MWh decreased for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to lower natural gas prices, which were partially offset by an increase in costs for the settlements of hedging instruments. Volume increased primarily due to the addition of the Higgins Generating Station in the fourth quarter of 2008.

Purchased Power

	Three Months Ended March 31,
	2009		2008		Change from Prior Year
Purchased Power	$	88,206	$	93,750		-5.9	%

Purchased Power in thousands
of MWhs		735		1,196		-38.5	%
Average cost per MWh of
Purchased Power	$	120.01	$	78.39		53.1	%

Purchased power costs decreased for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to a decrease in volume. MWhs decreased primarily as a result of an increase in self generation and a decrease in total system demand. The average cost per MWh of purchased power increased significantly compared to prior period primarily due to an increase in the settlement costs for hedging instruments related to gas purchased for tolling contracts.

Deferral of Energy Costs - Net

	Three Months Ended March 31,
	2009		2008		Change from Prior Year

Deferral of energy costs - net	$	38,190	$	45,775		-16.6	%

Deferral of energy costs – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferral of energy costs – net also include the current amortization of fuel and purchased power costs previously deferred. Reference Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Amounts for the three months ended March 31, 2009 and 2008 include amortization of deferred energy costs of $8.2 million and $39.8 million, respectively; and an over-collection of amounts recoverable in rates of $30 million in 2009 and $6 million in 2008.

Allowance for Funds Used During Construction

	Three Months Ended March 31,
	2009		2008		Change from Prior Year

Allowance for other funds used during construction	$	5,621	$	6,858		-18.0	%

Allowance for borrowed funds used during construction		4,562		5,355		-14.8	%
	$	10,183	$	12,213		-16.6	%

AFUDC decreased for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to the completion of construction of the Clark Peaking Units in late 2008, partially offset by the construction of the 500 MW natural gas generating station at the existing Harry Allen Generating Station, which is expected to be operational by summer 2011.

Other (Income) and Expenses

	Three Months Ended March 31,
	2009			2008			Change from Prior Year

Other operating expense	$	70,193		$	57,095			23	%
Maintenance expense	$	27,534		$	16,650			65.4	%
Depreciation and amortization	$	52,363		$	40,630			28.9	%
Interest charges on long-term debt	$	52,308		$	40,997			27.6	%
Interest charges-other	$	7,297		$	5,831			25.1	%
Interest accrued on deferred energy	$	(1,853	)	$	(1,794	)		3.3	%
Other income	$	(2,342	)	$	(5,747	)		-59.2	%
Other expense	$	3,207		$	1,361			135.6	%

Other operating expense increased for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to costs associated with renewable energy programs, increased pension and other post retirement expenses, and operating expenses for the Higgins Generating Station acquired in October 2008.

Maintenance expense increased for the three months ended March 31, 2009, compared to the same period in 2008, due to the addition of the Higgins Generating Station and scheduled maintenance at the Clark, Navajo and Silverhawk Generating Stations.

Depreciation and amortization expenses increased during the three months ended March 31, 2009, compared to the same period in 2008, as a result of additions to plant-in-service. Plant-in-service increased primarily due to the completion of the Clark Peaking Units and the addition of the Higgins Generating Station in the latter part of 2008.

Interest charges on Long-Term Debt for the three months ended March 31, 2009, compared to the same period in 2008 increased primarily due to the issuance of $1.1 billion additional debt used to fund significant capital expenditures. This increase was partially offset by lower interest on variable rate debt. See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2008 Form 10-K for additional information regarding long-term debt and Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements in this Form 10-Q.

Interest charges-other for the three months ended March 31, 2009, compared to the same period in 2008 increased due to interest on taxes and higher amortization costs related to new debt issues and redemptions.

Interest accrued on deferred energy costs for the three months ended March 31, 2009 compared to the same period in 2008 did not change significantly.

Other income for the three months ended March 31, 2009, compared to the same period in 2008 decreased primarily due to income earned in 2008 as a result of the settlement with Calpine, and the subsequent gain on sale of the stock received, as discussed further in Note 13, Commitments and Contingencies in the Notes to Financial Statements in the 2008 Form 10-K. Also contributing to the decrease in other income was the expiration of the amortization of gains associated with the disposition of property and lower interest income. This decrease was partially offset by higher carrying charges on energy conservation programs in 2009.

Other expense for the three months ended March 31, 2009, compared to the same period in 2008 increased primarily due to the write-off of permitting costs.

ANALYSIS OF CASH FLOWS

Cash flows increased during the three months ended March 31, 2009 compared to the same period in 2008 primarily due to an increase in cash from financing activities partially offset by a decrease in cash from operating activities.

Cash Used By Operating Activities. The decrease in cash from operating activities was primarily due to lower revenues as a result of milder weather and to a lesser extent, changes in customer usage patterns. Also contributing to the decrease in cash from operating activities was an increase in costs for operations and maintenance costs for generating facilities, the funding of approximately $20 million for pension plans, prepayments for land leases and in 2008, NPC received a significant prepayment for transmission services.

Cash Used By Investing Activities. Cash used for investing activities did not change significantly between the periods.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on NPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.

As of March 31, 2009, NPC had cash on hand of approximately $81.6 million. NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, NPC may issue debt up to $281.5 million, on a consolidated basis, which includes the use of approximately $268.0 million of the Utilities’ revolving credit facilities. NPC anticipates with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that cash on hand, internally generated funds and the ability to issue debt, which includes the use of the NPC’s revolving credit facility, will be sufficient to meet short-term operating costs. However, if energy costs rise at a rapid rate and NPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to NPC could be significantly less. In order to maintain sufficient liquidity, NPC may be required to further delay capital expenditures, re-finance debt or obtain funding through an equity issuance by NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter and the Utilities may not be able to fully utilize the availability on their revolving credit facilities. NVE and the Utilities are projecting that their ability to issue debt will increase in the second and third quarter of 2009, as the Utilities’ operating income typically increases during this time period, and new rates as a result of NPC’s GRC are expected to be in effect beginning July 1, 2009.

NPC does not have significant debt maturities in 2009 or 2010 other than its revolving credit facilities. As of April 30, 2009, NPC had $18.3 million outstanding on its revolving credit facilities including letters of credit. NPC’s long-term credit facility expires in November 2010, and NPC’s Supplemental Revolving Credit Facility expires in January 2010.

There have been no changes to the credit ratings of NPC in the first quarter of 2009, other than DBRS’ election to discontinue coverage on a majority of their U.S. clients (see Credit Ratings, below). However, disruptions in the banking and capital markets not specifically related to NVE or the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

During the three months ended March 31, 2009, there were no material changes to contractual obligations as set forth in NPC’s 2008 Form 10-K, except as discussed under financing transactions below.

Financing Transactions

Revolving Credit Facilities

General and Refunding Mortgage Notes, Series V

General and Refunding Mortgage Notes, Series U

Factors Affecting Liquidity

Ability to Issue Debt

Ability to Issue General and Refunding Mortgage Securities

To the extent that NPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under NPC’s General and Refunding Mortgage Indenture (“Indenture”).

The Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of March 31, 2009, $4.0 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $499.3 million of General and Refunding Mortgage Securities as of March 31, 2009. That amount is determined on the basis of:

1.		70% of net utility property additions;
2.		the principal amount of retired General and Refunding Mortgage Securities; and/or
3.		the principal amount of first mortgage bonds retired after October 2001.

Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

Credit Ratings

NPC’s senior secured debt is rated investment grade by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. DBRS is no longer covering NPC. As of March 31, 2009, the ratings are as follows:

		Rating Agency
		Fitch	Moody’s	S&P
NPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*
NPC	Sr. Unsecured Debt	BB	Not rated	BB+

* Investment grade

S&P’s and Moody’s rating outlook for NPC is Stable. Fitch’s rating outlook is Positive.

Energy Supplier Matters

With respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of March 31, 2009 for all suppliers continuing to provide power under a WSPP agreement would approximate a $186.6 million payment or obligation to NPC. These contracts qualify for the normal purchases scope exception of SFAS 133, and as such, are not required to be marked-to-market on the balance sheet. Refer to Note 5, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements for further discussion.

Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counter-parties require payment in advance of delivery.

Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has one transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. For this counterparty if NPC’s senior secured ratings from both Moody’s and S&P are below investment grade, the maximum collateral amount would be $46.1 million. If NPC’s senior unsecured rating from both Moody’s and S&P are below investment grade the maximum collateral requirement would be $11.5 million.

Financial Gas Hedges

NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that NPC maintain its Moody’s and S&P senior unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that NPC’s senior unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require NPC to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to NPC, subject to certain caps. As of March 31, 2009, the maximum amount of collateral NPC would be required to post under these agreements is approximately $215.3 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $116.8 million would be required if NPC is downgraded one level and an additional amount of approximately $98.5 million would be required if NPC is downgraded two levels.

Cross Default Provisions

None of the financing agreements of NPC contains a cross-default provision that would result in an event of default by NPC upon an event of default by NVE or SPPC under any of its financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $19.1million for the three months ended March 31, 2009 compared to net income of $24.3 million for the same period in 2008.

As of March 31, 2009, SPPC had paid $108.8 million in dividends to NVE. During the first quarter of 2009, NVE contributed capital of $90.3 million to SPPC. On April 30, 2009, SPPC declared an additional $20 million dividend to NVE.

Gross margin is presented by SPPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric and gas businesses are at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business.

SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less fuel and purchased power costs, provides a measure of income available to support the other operating expenses of SPPC. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect SPPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

The components of gross margin for the three months ended March 31 were (dollars in thousands):

	Three Months Ended March 31,
	2009			2008		Change from Prior Year
Operating Revenues:
Electric	$	237,738		$	250,278		-5.0	%
Gas		80,993			85,594		-5.4	%
	$	318,731		$	335,872		-5.1	%

Energy Costs:
Fuel for power generation	$	76,042		$	57,587		32.0	%
Purchased power		37,181			90,106		-58.7	%
Gas purchased for resale		70,272			66,896		5.0	%
Deferral of energy costs-electric-net		11,796			8,507		38.7	%
Deferral of energy costs-gas-net		(4,351	)		2,203		-297.5	%
	$	190,940		$	225,299		-15.3	%
Energy Costs by Segment:
Electric	$	125,019		$	156,200		-20.0	%
Gas		65,921			69,099		-4.6	%
	$	190,940		$	225,299		-15.3	%

Gross Margin by Segment:
Electric	$	112,719		$	94,078		19.8	%
Gas		15,072			16,495		-8.6	%
	$	127,791		$	110,573		15.6	%

Electric gross margin increased in the first quarter of 2009 compared to the same period in 2008, primarily due to the increase in BTGR revenue as a result of SPPC’s 2007 GRC, effective July 1, 2008 and a slight increase in average customer growth, partially offset by a change in customer usage patterns and milder winter weather.

Gas gross margin decreased in the first quarter of 2009 compared to the same period in 2008, primarily due to decreased customer usage as a result of milder winter weather.

The causes of significant changes in specific lines comprising the results of operations are provided below (dollars in thousands except for amounts per unit):

Electric Operating Revenue

	Three Months Ended March 31,
	2009		2008		Change from Prior Year
Electric Operating Revenues:
Residential	$	93,785	$	89,879		4.3	%
Commercial		90,437		87,671		3.2	%
Industrial		46,067		65,782		-30.0	%
Retail revenues		230,289		243,332		-5.4	%
Other		7,449		6,946		7.2	%
Total Revenues	$	237,738	$	250,278		-5.0	%

Retail sales in thousands
MWh		1,980		2,151		-7.9	%

Average retail revenues per MWh	$	116.31	$	113.13		2.8	%

SPPC’s retail revenues decreased for the three months ended March 31, 2009, as compared to the same period in the prior year, due to lower industrial revenues and decreased customer usage due to warmer 2009 winter temperatures. Industrial revenues decreased primarily due to the transition of Cortez Mine to DOS effective November 1, 2008, and a retail service agreement with Newmont Mining Corporation beginning June 1, 2008. These decreases were partially offset by increased retail rates and growth in retail customers. Retail rates increased as a result of SPPC’s various BTER quarterly cases, and increased BTGR as a result of the GRC effective July 1, 2008, which exceeded decreased deferred energy rates effective July 1, 2008 (see Note 3, Regulatory Actions of the Condensed Notes to Financial Statements). The average number of residential customers remain unchanged while the average number of commercial and industrial customers increased 1.7% and 4.6%, respectively.

In 2007, SPPC and Newmont Mining Corporation entered into a wholesale power sale agreement and a new form of retail service whereby Newmont Mining Corporation will sell the electrical output from it’s generating plant to SPPC for at least 15 years under a long-term wholesale purchase power agreement and remain a retail customer of SPPC during at least that period under the terms of the retail service agreement and pursuant to a new rate schedule. The terms of these contracts became effective on June 1, 2008, at which point Newmont Mining Corporation moved to a new retail service agreement at a reduced energy rate, which resulted in decreased electric revenues.

Electric Operating Revenues – Other increased for the three month period ended March 31, 2009, compared to the same period in 2008, primarily due to increased transmission revenues.

Gas Operating Revenues

	Three Months Ended March 31,
	2009		2008		Change from Prior Year
Gas Operating Revenues:
Residential	$	45,881	$	50,747		-9.6	%
Commercial		21,840		24,409		-10.5	%
Industrial		5,892		7,987		-26.2	%
Retail revenues		73,613		83,143		-11.5	%
Wholesale		6,734		1,679		301.1	%
Miscellaneous		646		772		-16.3	%
Total Revenues	$	80,993	$	85,594		-5.4	%

Retail sales in thousands
of Dths		6,107		6,782		-10.0	%

Average retail revenues per Dth	$	12.05	$	12.26		-1.7	%

SPPC’s retail gas revenues decreased for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to milder weather and decreases in retail customer rates. Retail rates decreased as a result of SPPC’s 2008 Natural Gas and Propane Deferred Rate Case and BTER updates. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2008 Form 10-K.

Wholesale revenues increased for the three months ended March 31, 2009, compared to the same period in 2008 primarily due to increased availability of gas for wholesale sales.

Energy Costs

Energy Costs include Fuel for Generation and Purchased Power. These costs are dependent upon many factors which may vary by season or period. As a result, SPPC’s usage and average cost per MWh of Fuel for Generation versus Purchased Power can vary significantly as the company meets the demands of the season. These factors include, but are not limited to:

●		Weather
●		Plant outages
●		Total system demand
●		Resource constraints
●		Transmission constraints
●		Gas transportation constraints
●		Natural gas constraints
●		Long-term contracts
●		Mandated power purchases; and
●		Generation efficiency

	Three Months Ended March 31,
					Change from
	2009		2008		Prior Year

Energy Costs	$	113,223	$	147,693		-23.3	%
Total System Demand (MWhs)		2,149		2,285		-6.0	%
Average cost per MWh	$	52.68	$	64.64		-18.5	%

Energy costs and the average cost per MWh for the period ending March 31, 2009 decreased compared to the same period in 2008 primarily due to a significant decrease in natural gas prices and lower purchased power costs primarily as a result of the Newmont Mining Corporation power purchase agreement discussed above. Total system demand decreased primarily due to milder weather in 2009, certain customers switching to DOS and a change in customer usage patterns. For the three months ended March 31, 2009, self generation represented 60% of total system demand compared to 43% for the same period in 2008.

Fuel For Power Generation

	Three Months Ended March 31,
					Change from
	2009		2008		Prior Year

Fuel for Power Generation	$	76,042	$	57,587		32.0	%

Thousands of MWh generated		1,279		992		28.9	%
Average fuel cost per MWh
of Generated Power	$	59.45	$	58.05		2.4	%

Fuel for power generation and average cost per MWh increased for the three months ended March 31, 2009, as compared to the same period in 2008. The increase was primarily due to an increase in volume and higher costs associated with the settlement of hedging instruments partially offset by a decrease in natural gas prices. Volume increased as a result of greater reliance on the Tracy Generating Station which was placed in service in the summer of 2008.

Purchased Power

	Three Months Ended March 31,
					Change from
	2009		2008		Prior Year

Purchased Power:	$	37,181	$	90,106		-58.7	%

Purchased Power in thousands of MWhs		870		1,293		-32.7	%

Average cost per MWh of Purchased Power	$	42.74	$	69.69		-38.7	%

Purchased Power costs and the average cost per MWh decreased for the three months ended March 31, 2009 as compared to the same period in 2008 primarily due to a decrease in volume and a power purchase agreement with Newmont Mining Corporation, as discussed above, whereby SPPC purchases power substantially below current market prices; however, SPPC was limited by the volume it could purchase at these lower rates.

Gas Purchased for Resale

	Three Months Ended March 31,
					Change from
	2009		2008		Prior Year

Gas Purchased for Resale	$	70,272	$	66,896		5.0	%

Gas Purchased for Resale
(in thousands of Dths)		7,781		7,146		8.9	%

Average cost per Dth	$	9.03	$	9.36		-3.5	%

Gas purchased for resale increased for the three months ended March 31, 2009 compared to the same period in 2008 primarily due to increased volume. The average cost per Dth decreased slightly as a result of lower natural gas prices partially offset by higher costs for the settlement of hedging instruments.

Deferral of Energy Costs

	Three Months Ended March 31,
	2009			2008		Change from Prior Year

Deferral of energy costs – electric – net	$	11,796		$	8,507		38.7	%
Deferral of energy costs - gas - net		( 4,351	)		2,203		-297.5	%
Total	$	7,445		$	10,710

Deferral of energy costs – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates the difference is recognized as an increase in costs. Deferral of energy costs – net also include the current amortization of fuel and purchased power costs previously deferred Reference Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Deferral of energy costs - electric – net for the three months ended March 31, 2009 and 2008 reflect amortization of deferred energy costs of ($0.8) million and $10 million, respectively; and an over-collection of amounts recoverable in rates of $12.6 million in 2009 and an under-collection of $1.5 million in 2008.

Deferred energy costs - gas - net for the three months ended March 31, 2009 and 2008 reflect amortization of deferred energy costs of $0 million, and ($0.6) million, respectively; and an under-collection of amounts recoverable in rates in 2009 of $4.4 million and an over-collection of $2.8 million in 2008.

Allowance for Funds Used During Construction

	Three Months Ended March 31,
	2009		2008		Change from Prior Year

Allowance for other funds
used during construction	$	597	$	5,099		-88.3	%

Allowance for borrowed funds
used during construction		584		3,797		-84.6	%
	$	1,181	$	8,896		-86.7	%

AFUDC decreased for the three months ended March 31, 2009, compared to the same period in 2008, primarily due to the completion of the Tracy Generating Station in July of 2008, which resulted in decrease in the CWIP balance.

Other (Income) and Expense

	Three Months Ended March 31,
	2009			2008			Change from Prior Year

Other operating expense	$	44,015		$	33,505			31.4	%
Maintenance expense	$	6,866		$	6,472			6.1	%
Depreciation and amortization	$	25,685		$	21,440			19.8	%
Interest charges on long-term debt	$	16,815		$	18,762			-10.4	%
Interest charges-other	$	1,696		$	1,622			4.6	%
Interest accrued on deferred energy	$	673		$	558			20.6	%
Other income	$	(2,715	)	$	(7,735	)		-64.9	%
Other expense	$	1,991		$	1,800			10.6	%

Other operating expense increased for the three months ended March 31, 2009 compared to the same period in 2008 primarily due to higher pension expenses, costs related to renewable energy programs and lower provisions for bad debt in 2008 compared to 2009.

Maintenance expense increased for the three months ended March 31, 2009 compared to the same period in 2008 primarily due to the addition of the Tracy Generating Station Combined Cycle units that became operational in summer of 2008, partially offset by outages at Ft. Churchill Generating Station during the first quarter of 2008.

Depreciation and amortization expenses increased for the three months ended March 31, 2009, compared to the same period in 2008, as a result of increases in plant-in-service, primarily due to the completion of the Tracy Generating Station in July of 2008.

Interest charges on long-term debt for the three months ended March 31, 2009 decreased from the same period in 2008 primarily due to the repurchase of certain variable rate debt, lower interest rates on variable rate debt, and the redemption of $99 million Series A General and Refunding Mortgage Bonds in June 2008. These amounts were partially offset by the issuance of $250 million Series Q General and Refunding Mortgage Notes in September 2008 and higher long term credit facility balances in 2009. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2008 Form 10-K for additional information regarding long-term debt and Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements in this Form 10-Q.

Interest charges-other for the three months ended March 31, 2009 did not change materially from the same period in 2008.

Interest accrued on deferred energy for the three months ended March 31, 2009, compared to the same period in 2008, due to higher over-collected deferred energy balances compared to the same period in 2008. See Note 3, Regulatory Actions of the Condensed Notes to Financial Statements for further details of deferred energy balances.

Other income for the three months ended March 31, 2009, compared to the same period in 2008, decreased primarily due to income earned in 2008 related to the reinstatement of previously disallowed costs associated with Pinon Pine in 2008, as discussed in Note 3, Regulatory Actions of the Notes to the Financial Statements in the 2008 Form 10-K and the settlement with Calpine discussed in Note 13, Commitments and Contingencies of the Notes to Financial Statements in the 2008 Form 10-K. These decreases to income were partially offset by interest income from a tax refund.

Other expense increased during the three months ended March 31, 2009, when compared to the same period in 2008, due to several items, each of which is not materially significant.

ANALYSIS OF CASH FLOWS

Cash flows decreased during the three months ended March 31, 2009 compared to the same period in 2008 primarily due to a decrease in cash from financing activities and a decrease in cash from operating activities, partially offset by a decrease in cash used for investing activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to lower revenues as a result of milder weather, a decrease in accounts payable from December 31, 2009 for energy and other suppliers and the timing of interest payments, offset partially by reduced spending for regulatory activities.

Cash Used By Investing Activities. Cash used by investing activities decreased slightly due to reduced construction for growth.

Cash From Financing Activities. The decrease in cash from financing activities is primarily due to higher dividends paid to NVE partially offset by increased investment by NVE.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.

As of March 31, 2009, SPPC had cash on hand of approximately $28.9 million. SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, SPPC may issue debt up to $281.5 million, on a consolidated basis, which includes the use of approximately $268.0 million of the Utilities’ revolving credit facilities. SPPC anticipates with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that cash on hand, internally generated funds and the ability to issue debt, which includes the use of the SPPC’s revolving credit facility, will be sufficient to meet short-term operating costs. However, if energy costs rise at a rapid rate and SPPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less. In order to maintain sufficient liquidity, SPPC may be required to further delay capital expenditures, refinance debt or obtain funding through an equity issuance by NVE.

SPPC does not have significant debt maturities in 2009 or 2010 other than its revolving credit facility. As of April 30, 2009, SPPC had $206.1 million outstanding on its revolving credit facility, including letters of credit. SPPC’s long-term credit facility expires in November 2010.

There have been no changes to the credit ratings of SPPC in the first quarter of 2009, other than DBRS’ election to discontinue coverage on a majority of their U.S. clients (see Credit Ratings, below). However, disruptions in the banking and capital markets not specifically related to SPPC may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

During the three months ended March 31, 2008, there were no material changes to contractual obligations as set forth in SPPC’s 2008 Form 10-K, except as discussed under financing transactions below.

Financing Transactions

Revolving Credit Facility

On March 2, 2009, SPPC amended its $350 million Amended and Restated Revolving Credit Agreement, due November 2010, to remove a bankrupt lending bank from the facility. This amendment reduced the capacity of the facility to approximately $332 million.

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

In January 2009, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007A bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Water Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Water Bonds, until such time as SPPC determines to reoffer the Water Bonds to investors. These Water Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness will be offset for presentation purposes.

Factors Affecting Liquidity

Ability to Issue Debt

As of March 31, 2009, SPPC had approximately $495 million of PUCN financing authority, which expires on December 31, 2009.

All other financial covenants contained in SPPC’s revolving credit facility and financing agreements are suspended as SPPC’s Senior Secured debt is rated investment grade. However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations on indebtedness under these covenants.

Ability to Issue General and Refunding Mortgage Securities

To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under SPPC’s General and Refunding Mortgage Indenture (“Indenture”).

1.	70% of net utility property additions;
2.	the principal amount of retired General and Refunding Mortgage Securities; and/or
3.	the principal amount of first mortgage bonds retired after October 2001.

Property Additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

Credit Ratings

SPPC’s senior secured debt is rated investment grade by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. DBRS is no longer covering SPPC. As of March 31, 2009, the ratings are as follows:

		Rating Agency
		Fitch	Moody’s	S&P
SPPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*

* Investment grade

S&P’s, and Moody’s rating outlook for SPPC is Stable. Fitch’s rating outlook is Positive.

Energy Supplier Matters

With respect to SPPC’s contracts for purchased power, SPPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that SPPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. Under the net mark-to-market value as of March 31, 2009 for all suppliers continuing to provide power under a WSPP agreement no amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception of SFAS 133, and as such, are not required to be mark-to-market on the balance sheet. Refer to Note 5, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements for further discussion.

Gas Supplier Matters

With respect to the purchase and sale of natural gas SPPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counterparties require payment in advance of delivery.

Financial Gas Hedges

SPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that SPPC maintain its Moody’s and S&P Sr. Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that SPPC’s Sr. Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require SPPC to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to SPPC, subject to certain caps. As of March 31, 2009, the maximum amount of collateral SPPC would be required to post under these agreements is approximately $97.7 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $54.4 million would be required if SPPC is downgraded one level and an additional amount of approximately $43.3 million would be required if SPPC is downgraded two levels.

Cross Default Provisions

None of the financing agreements of SPPC contains a cross-default provision that would result in an event of default by SPPC upon an event of default by NVE or SPPC under any of its financing agreements. In addition, certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.

REGULATORY PROCEEDINGS (UTILITIES)

NVE is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, NVE and all of its subsidiaries (whether or not engaged in any energy related business) are required to maintain books, accounts and other records in accordance with FERC regulations and to make them available to the FERC, the PUCN and CPUC. In addition, the PUCN, CPUC, or the FERC have the authority to review allocations of costs of non-power goods and administrative services among NVE and its subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions between NVE, NPC and/or SPPC and/or any other affiliated company.

The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. NPC and SPPC submit IRPs to the PUCN for approval.

Under federal law, the Utilities are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.

As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

The Utilities are required to file annual electric and gas DEAA cases on March 1 as mandated by the 2007 Nevada Legislature, quarterly BTER Updates for the Utilities’ electric and gas departments, and triennial GRCs in Nevada. A DEAA case is filed to recover or refund any under or over collection of prior energy costs and the BTER Updates recover current energy costs. As of March 31, 2009, NPC’s and SPPC’s balance sheets included approximately $245.5 million and credits of $36.5 million, respectively, of deferred energy costs of which $168.1 million and credits of $11.2 million had been previously approved for collection over various periods. The remaining amounts will be requested in future DEAA filings. Refer to Note 3, Regulatory Actions of the Condensed Notes to Financial Statements. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital.

Rate case applications filed in 2008 and 2009, as well as other regulatory matters such as, the Utilities’ IRPs and subsequent amendments, other Nevada matters, California matters and FERC matters, are discussed in more detail in Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements, and in the 2008 Form 10-K.

RECENT PRONOUNCEMENTS

See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements, for discussion of accounting policies and recent pronouncements.

ITEM 3A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of March 31, 2009, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).

	March 31, 2009
	Expected Maturity Date
																					Fair
	2009		2010			2011			2012			2013			Thereafter			Total			Value
Long-term Debt
NVE
Fixed Rate	$	-	$	-		$	-		$	63,670		$	-		$	421,539		$	485,209		$	425,780
Average Interest Rate		-		-			-			7.80	%		-			7.77	%		7.78	%

NPC
Fixed Rate	$	-	$	-		$	364,000		$	130,000		$	-		$	2,894,335		$	3,388,335		$	3,161,285
Average Interest Rate		-		-			8.14	%		6.50	%		-			6.53	%		6.70	%
Variable Rate	$	-	$	-		$	-		$	-		$	-		$	179,500		$	179,500		$	179,500
Average Interest Rate		-		-			-			-			-			1.35	%		1.35	%

SPPC
Fixed Rate	$	-	$	-		$	-		$	100,000		$	250,000		$	625,000		$	975,000		$	901,502
Average Interest Rate		-		-			-			6.25	%		5.45	%		6.39	%		6.13	%
Variable Rate	$	-	$	199,930		$	-		$	-		$	-		$	218,500		$	418,430		$	418,430
Average Interest Rate		-		1.29	%		-			-			-			1.46	%		1.38	%

Total Debt	$	-	$	199,930		$	364,000		$	293,670		$	250,000		$	4,338,874		$	5,446,474		$	5,086,497

Commodity Price Risk

See the 2008 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk. No material changes in commodity risk have occurred since December 31, 2008.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $199.8 million as of March 31, 2009, which compares to balances of $334.3 million at December 31, 2008, and $187.9 million at March 31, 2008. The decrease from December 31, 2008 is primarily due to the decrease in prices of natural gas during the first quarter of 2009.

ITEM 4 AND ITEM 4T. CONTROLS AND PROCEDURES

(a)	Evaluation of disclosure controls and procedures.

NVE, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of March 31, 2009, the registrants’ disclosure controls and procedures were effective.

(b)	Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the first quarter of 2009 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

As of the date of this report, there have been no material changes with regard to administrative and judicial proceedings involving regulatory, environmental and other matters as disclosed in NVE’s, NPC’s and SPPC’s 2008 Form 10-K, except as discussed below.

Nevada Power Company and Sierra Pacific Power Company

Western United States Energy Crisis Proceedings before the FERC

FERC 206 complaints

In December 2001, the Utilities filed ten complaints with the FERC against various power suppliers, including Enron, under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in June 2001 in reaction to the Western United States energy crisis. The Utilities contested the amounts paid for power actually delivered as well as termination claims for undelivered power against terminating suppliers.

In June 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the Utilities had failed to satisfy their burden of proof under the strict public interest standard. In July 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June decision (“July decision”). The Utilities appealed this decision to the Ninth Circuit. In December 2006, a three judge panel of the Ninth Circuit overturned the July decision and remanded the case back to the FERC for application of the factors that the Ninth Circuit outlines in its decision. In May 2007, American Electric Power Service Corporation and Allegheny Energy Supply Company and other interested parties filed petitions for certiorari (“Petitions”) with the U.S. Supreme Court seeking review of the Ninth Circuit’s decision. The Utilities, together with other parties and the FERC, filed their opposition to these Petitions in August 2007. In September 2007, the U.S. Supreme Court granted certiorari. In June 2008, the U.S. Supreme Court rejected the Ninth Circuit’s reasoning in reversing the FERC but nonetheless found that FERC’s order was defective and should be reversed for other reasons. The case was remanded to the FERC. The FERC established a formal settlement discussion protocol for bilateral settlement discussions with other respondents, including Allegheny Energy Supply Company, American Electric Power Service Corporation and BP Energy, and stayed the case pending settlement discussions. The Utilities have reached an agreement in principle with BP Energy and continue discussions with Allegheny Energy Supply Company and American Electric Power Service Corporation.

The Utilities previously had negotiated settlements with Duke Energy Trading and Marketing, Morgan Stanley Capital Group, El Paso Merchant Energy, now known as El Paso Marketing L.P., Calpine Energy Services and Enron. Management cannot predict the timing or outcome of a decision in this matter.

ITEM 1A. RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to NVE on a consolidated basis (including NPC and SPPC). The following information updates, and should be read in conjunction with, the information disclosed in Item 1A, “Risk Factors,” of our 2008 Form 10-K. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in NVE’s, NPC’s and SPPC’s 2008 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

Amendments to Articles of Incorporation; By-laws

The 2009 Annual Meeting of the Stockholders of NVE was held at 10:00 a.m., Pacific Daylight Time, on Thursday, April 30, 2009, at the General Office Building of NV Energy in Reno, Nevada. All proposals presented for stockholder consideration were approved, including a proposal to amend NVE’s Articles of Incorporation to provide for the phase-in of annual election of Directors. The amendment to NVE’s Articles of Incorporation is described in NVE’s definitive Proxy Statement dated March 20, 2009 and filed with the SEC. The amendment became effective upon its filing with the Secretary of State of Nevada on April 30, 2009. A complete copy of NVE’s Articles of Incorporation as amended is filed as an exhibit to this Report.

In furtherance of the amendment to Articles of Incorporation, the Board of Directors of NVE, on May 1, 2009, amended Article VIII of NVE’s By-laws to eliminate the references to a classified Board and to clarify that the Board may fix the number of Directors from time to time by an affirmative vote of two-thirds of the entire Board of Directors. A complete copy of NVE’s By-laws as amended is filed as an exhibit to this Report.

The final voting results for the 2009 Annual Meeting of Stockholders will be disclosed in NVE's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2009.

ITEM 6. EXHIBITS

(a)	Exhibits filed with this Form 10-Q:

(3) NV Energy, Inc.:

3.1 Restated and Amended Articles of Incorporation of NV Energy, Inc. dated May 1, 2009.

3.2 By-laws of NV Energy, Inc., as amended through May 1, 2009.

(10) Nevada Power Company:

10.1 Second Amendment, dated November 25, 2008 (effective March 17, 2009), to the Second Amended and Restated Credit Agreement, dated November 4, 2005, among Nevada Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein.

10.2. Fourth Amendment, dated February 10, 2009 (effective February 24, 2009), to the Second Amended and Restated Credit Agreement, dated November 4, 2005, among Nevada Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein.

Sierra Pacific Power Company:

10.3 Second Amendment, dated November 25, 2008 (effective March 17, 2009) to the Amended and Restated Credit Agreement, dated November 4, 2005, among Sierra Pacific Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein.

10.4. Third Amendment, dated February 10, 2009 (effective February 24, 2009), to the Amended and Restated Credit Agreement, dated November 4, 2005, among Sierra Pacific Power Company, Wachovia Bank, National Association, as Administrative Agent, the Lenders from time to time party thereto and the other parties named therein.

(12) NV Energy, Inc.:

12.1 Statement regarding computation of Ratios of Earnings to Fixed Charges.

Nevada Power Company:

12.2 Statement regarding computation of Ratios of Earnings to Fixed Charges.

Sierra Pacific Power Company:

12.3 Statement regarding computation of Ratios of Earnings to Fixed Charges.

(31) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

31.1 Certification of Chief Executive Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Annual Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.3 Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4 Certification of Chief Financial Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.5 Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.6 Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

32.1 Certification of Chief Executive Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.3 Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4 Certification of Chief Financial Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.5 Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.6 Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.


	Sierra Pacific Resources d/b/a NV Energy
	(Registrant)

Date: May 4, 2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: May 4, 2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

	Nevada Power Company d/b/a NV Energy
	(Registrant)

Date: May 4, 2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: May 4, 2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

	Sierra Pacific Power Company d/b/a NV Energy
	(Registrant)

Date: May 4, 2009	By:	/s/ William D. Rogers
		William D. Rogers
		Chief Financial Officer
		(Principal Financial Officer)

Date: May 4, 2009	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)